[Federal Register: January 22, 2001 (Volume 66, Number 14)][Rules and Regulations][Page 6849-6919]From the Federal Register Online via GPO Access [wais.access.gpo.gov][DOCID:fr22ja01-26][[Page 6849]]-----------------------------------------------------------------------Part IVEnvironmental Protection Agency-----------------------------------------------------------------------40 CFR Parts 9 and 435Effluent Limitations Guidelines and New Source Performance Standardsfor the Oil and Gas Extraction Point Source Category; OMB ApprovalUnder the Paperwork Reduction Act: Technical Amendment; Final Rule[[Page 6850]]-----------------------------------------------------------------------ENVIRONMENTAL PROTECTION AGENCY40 CFR Parts 9 and 435[FRL-6929-8]RIN 2040-AD14Effluent Limitations Guidelines and New Source PerformanceStandards for the Oil and Gas Extraction Point Source Category; OMBApproval Under the Paperwork Reduction Act: Technical AmendmentAGENCY: Environmental Protection Agency (EPA).ACTION: Final Rule; technical amendment.-----------------------------------------------------------------------SUMMARY: EPA is publishing final regulations establishing technology-based effluent limitations guidelines and standards for the dischargeof synthetic-based drilling fluids (SBFs) and other non-aqueousdrilling fluids from oil and gas drilling operations into waters of theUnited States. Oil and gas extraction facilities generate cuttingswastes from drilling operations. This regulation applies to existingand new sources that perform oil and natural gas extraction drilling incertain offshore and coastal waters. The final rule allows a controlleddischarge of SBF-cuttings anywhere offshore of Alaska and offshore ofthe rest of the United States beyond three miles from shore. Thisregulation prohibits discharge of such fluids in coastal Cook Inlet,Alaska, unless certain findings are made by the permit authority. Thefinal rule prohibits the discharge of SBFs not associated with drillcuttings into all waters of the United States.    Compliance with this rule is estimated to reduce the annualdischarge of cuttings by 118 million pounds per year for new andexisting sources. This rule will also lead to a decrease of 2,927 tonsof air emissions and 200,817 barrels of oil equivalent (BOE) per yearfor new and existing sources. EPA estimates that the rule will resultin annual savings of $48.9 million and no adverse economic impacts tothe industry as a whole. EPA also incorporated Best ManagementPractices (BMPs) into the final rule to provide industry withadditional flexibility in meeting today's final rule. In compliancewith the Paperwork Reduction Act (PRA), this action also makes atechnical amendment to the table in part 9 that lists the Office ofManagement and Budget (OMB) control numbers issued under the PRA fortoday's final rule. EPA is amending part 9 to include the OMB controlnumber for the information collection requirements associated with theBMPs promulgated in today's final rule.DATES: This regulation shall become effective February 21, 2001. Forjudicial review purposes, this final rule is promulgated as of 1 p.m.Eastern Time on February 5, 2001, as provided in 40 CFR 23.2. Theincorporation by reference of certain publications listed in theregulations is approved by the Director of the Office of FederalRegister as of February 21, 2001.ADDRESSES: The public record is available for review in the EPA WaterDocket, East Tower Basement, Room EB-57, 401 M St. SW., Washington, DC20460. The public record for this rule has been established underdocket number W-98-26, and includes supporting documentation, but doesnot include any information claimed as Confidential BusinessInformation (CBI). The record is available for inspection from 9 a.m.to 4 p.m., Monday through Friday, excluding legal holidays. For accessto docket materials, please call (202) 260-3027 to schedule anappointment.FOR FURTHER INFORMATION CONTACT: For additional technical informationcontact Mr. Carey A. Johnston at (202) 260-7186 or send E-mail to:johnston.carey@epa.gov. For additional economic information contact Mr.James Covington at (202) 260-5132 or send E-mail to:covington.james@epa.gov.SUPPLEMENTARY INFORMATION:Regulated Entities    Entities potentially regulated by this action include:------------------------------------------------------------------------           Category                  Examples of regulated entities------------------------------------------------------------------------Industry.....................  Facilities engaged in the drilling of                                wells in the oil and gas industry in                                areas defined as ``coastal'' or                                ``offshore'' and discharging in                                geographic areas where drilling wastes                                are allowed for discharge (anywhere                                offshore of Alaska and offshore of the                                rest of the United States beyond three                                miles from shore, and the coastal waters                                of Cook Inlet, Alaska). Includes certain                                facilities covered under Standard                                Industrial Classification code 13 and                                North American Industrial Classification                                System codes 211111 and 213111.------------------------------------------------------------------------    This table is not intended to be exhaustive, but rather provides aguide for readers regarding entities likely to be regulated by thisaction. This table lists the types of entities that EPA is now awarecould potentially be regulated by this action. Other types of entitiesnot listed in the table could also be regulated. To determine whetheryour facility is regulated by this action, you should carefully examinethe applicability criteria in 40 CFR part 435 (see Secs. 435.10 and435.40). If you have questions regarding the applicability of thisaction to a particular entity, consult the person listed for technicalinformation in the preceding FOR FURTHER INFORMATION CONTACT section.Compliance Dates    Deadlines for compliance with Best Practicable Control TechnologyCurrently Available (BPT), Best Conventional Pollutant ControlTechnology (BCT), and Best Available Technology Economically Achievable(BAT) are established in National Pollutant Discharge EliminationSystem (NPDES) permits. A new source must comply with New SourcePerformance Standards (NSPS) on the date the new source commencesdischarging.Technical Amendments to Part 9    EPA is amending the table of currently approved informationcollection request (ICR) control numbers issued by OMB for variousregulations. The amendment updates the table to list those informationcollection requirements promulgated under today's final rule. Theaffected regulations are codified at 40 CFR part 9. EPA will continueto present OMB control numbers in a consolidated table format to becodified in 40 CFR part 9 of the Agency's regulations, and in each CFRvolume containing EPA regulations. The table lists CFR citations withreporting, recordkeeping, or other information collection requirements,and the current OMB control numbers. This listing of the OMB controlnumbers and their subsequent codification in the CFR satisfies therequirements of the Paperwork Reduction Act (44 U.S.C. 3501 et seq.)and OMB's implementing regulations at 5 CFR part 1320.    This ICR was previously subject to public notice and comment priorto OMB approval. Due to the technical[[Page 6851]]nature of the table, EPA finds that further notice and comment isunnecessary. As a result, EPA finds that there is ``good cause'' undersection 553(b)(B) of the Administrative Procedure Act, 5 U.S.C.553(b)(B), to amend this table without prior notice and comment. As aresult of today's technical amendment pertaining to BMPs, EPA is nowauthorized under the Paperwork Reduction Act to conduct or sponsor theinformation collection requirements in 40 CFR 435.13, 435.15, 435.43,and 435.45.Supporting Documentation    The rules promulgated today are supported by several majordocuments:    1. ``Economic Analysis of Final Effluent Limitations Guidelines andStandards for Synthetic-Based Drilling Fluids and other Non-AqueousDrilling Fluids in the Oil and Gas Extraction Point Source Category''(EPA-821-B-00-012). Hereafter referred to as the SBF Economic Analysis,this document presents the analysis of compliance costs and/or savings;facility closures; and changes in rate of return. In addition, impactson employment and affected communities, foreign trade, specificdemographic groups, and new sources also are considered.    2. ``Development Document for Final Effluent Limitations Guidelinesand Standards for Synthetic-Based Drilling Fluids and other Non-AqueousDrilling Fluids in the Oil and Gas Extraction Point Source Category''(EPA-821-B-00-013). Hereafter referred to as the SBF DevelopmentDocument, the document presents EPA's technical conclusions concerningthe promulgated rules. This document describes, among other things, thedata collection activities, the wastewater treatment technologyoptions, effluent characterization, effluent reduction of thewastewater treatment technology options, estimate of costs to theindustry, and estimate of effects on non-water quality environmentalimpacts.    3. ``Environmental Assessment of Final Effluent LimitationsGuidelines and Standards for Synthetic-Based Drilling Fluids and otherNon-Aqueous Drilling Fluids in the Oil and Gas Extraction Point SourceCategory'' (EPA-821-B-00-014). Hereafter referred to as the SBFEnvironmental Assessment, the document presents the analysis of waterquality impacts for each regulatory option. EPA describes theenvironmental characteristics of SBF drilling wastes, types ofanticipated impacts, and pollutant modeling results for water columnconcentrations, pore water concentrations, and human health effects viaconsumption of affected seafood.    4. ``Statistical Analyses Supporting Final Effluent LimitationsGuidelines and Standards for Synthetic-Based Drilling Fluids and otherNon-Aqueous Drilling Fluids in the Oil and Gas Extraction Point SourceCategory'' (EPA-821-B-00-015). Hereafter referred to as the SBFStatistical Support Document, this document presents analyses ofretention on cuttings of SBF. EPA describes the performancecharacteristics of cuttings treatment technologies and calculatessummary statistics for use as numerical limits.How To Obtain Supporting Documents    All documents are available from the National Service Center forEnvironmental Publications, PO Box 42419, Cincinnati, OH 45242-2419,(800) 490-9198. The supporting technical documentation (e.g., SBFDevelopment Document) and previous technical documentation and FederalRegister notices can also be obtained on the Internet, located atWWW.EPA.GOV/OST/GUIDE. This website also links to an electronic versionof today's final rule.Overview    This preamble includes a description of the legal authority forthese final regulations; a summary of the final regulations; backgroundinformation on the industry and its processes; a description of thetechnical and economic methodologies and data used by EPA to developthese regulations; and a summary of EPA responses to major commentsreceived on the Proposal (February 3, 1999; 64 FR 5488) and Notice ofData Availability (April 21, 2000; 65 FR 21548). The definitions,acronyms, and abbreviations used in this preamble are defined inAppendix A.Organization of This DocumentI. Legal AuthorityII. Background    A. Clean Water Act    B. Pollution Prevention Act    C. Profile of Industry    D. Proposed Rule    E. Notice of Data AvailabilityIII. Summary of Data and Information Received in Response to theNotice of Data Availability    A. Pollutant Loading and Numeric Limit Analyses    B. Compliance Costs Analyses    C. Economic Impacts Analyses    D. Water Quality Impact and Human Health Analyses    E. Non-Water Quality Environmental Impact Analyses    F. Compliance Analytical MethodsIV. Summary of Revisions Based on Notice of Data AvailabilityComments    A. Pollutant Loading Analyses    B. Compliance Costs Analyses    C. Economic Impacts Analyses    D. Water Quality Impact and Human Health Analyses    E. Non-Water Quality Environmental Impact Analyses    F. Numerical Limits for Retention of SBF Base Fluid on SBF-cuttingsV. Development and Selection of Effluent Limitations Guidelines andStandards    A. Waste Generation and Characterization    B. Selection of Pollutant Parameters    C. Regulatory Options Considered and Selected for Drilling FluidNot Associated with Drill Cuttings    D. BPT Technology Options Considered and Selected for DrillingFluid Associated with Drill Cuttings    E. BCT Technology Options Considered and Selected for DrillingFluid Associated with Drill Cuttings    F. BAT Technology Options Considered and Selected for DrillingFluid Associated with Drill Cuttings    G. NSPS Technology Options Considered and Selected for DrillingFluid Associated with Drill Cuttings    H. PSES and PSNS Technology Options    I. Best Management Practices (BMPs) to Demonstrate Compliancewith Numeric BAT Limitations and NSPS for Drilling Fluid Associatedwith Drill CuttingsVI. Costs and Pollutant Reductions for Final Regulation    A. Compliance Costs    B. Pollutant ReductionsVII. Economic Impacts of Final Regulation    A. Impacts Analysis    B. Small Business AnalysisVIII. Water Quality and Non-Water Quality Environmental Impacts ofFinal Regulation    A. Overview of Water Quality and Non-Water Quality EnvironmentalImpacts    B. Water Quality Modeling    C. Human Health Effects Modeling    D. Seabed Surveys    E. Energy Impacts    F. Air Emission Impacts    G. Air Emissions Monetized Human Health Benefits    H. Solid Waste Impacts    I. Other FactorsIX. Regulatory Requirements    A. Executive Order 12866: Regulatory Planning and Review    B. Regulatory Flexibility Act (RFA), as amended by the SmallBusiness Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5U.S.C. 601 et seq.    C. Submission to Congress and the General Accounting Office    D. Paperwork Reduction Act    E. Unfunded Mandates Reform Act    F. Executive Order 13084: Consultation and Coordination withIndian Tribal Governments    G. Executive Order 13132: Federalism    H. National Technology Transfer and Advancement Act    I. Executive Order 13045: Protection of Children fromEnvironmental Health Risks and Safety Risks[[Page 6852]]    J. Executive Order 13158: Marine Protected AreasX. Regulatory Implementation    A. Implementation of Limitations and Standards    B. Upset and Bypass Provisions    C. Variances and Modifications    D. Relationship of Effluent Limitations to NPDES Permits &Monitoring Requirements    E. Analytical MethodsAppendix A: Definitions, Acronyms, and Abbreviations Used in ThisPreambleI. Legal Authority    EPA is promulgating these regulations under the authority ofsections 301, 304, 306, 307, 308, 402, and 501 of the Clean Water Act,33 U.S.C. 1311, 1314, 1316, 1317, 1318, 1342 and 1361. The technicalamendment to part 9 is promulgated under the authority of 7 U.S.C. 135et seq., 136-136y; 15 U.S.C. 2001, 2003, 2005, 2006, 2601-2671; 21U.S.C. 331j, 346a, 348; 31 U.S.C. 9701; 33 U.S.C. 1251 et seq., 1311,1313d, 1314, 1318, 1321, 1326, 1330, 1342, 1344, 1345 (d) and (e),1361; E.O. 11735, 38 FR 21243, 3 CFR, 1971-1975 Comp. p. 973; 42 U.S.C.241, 242b, 243, 246, 300f, 300g, 300g-1, 300g-2, 300g-3, 300g-4, 300g-5, 300g-6, 300j-1, 300j-2, 300j-3, 300j-4, 300j-9, 1857 et seq., 6901-6992k, 7401-7671q, 7542, 9601-9657, 11023, 11048.II. BackgroundA. Clean Water Act    Congress adopted the Clean Water Act (CWA) to ``restore andmaintain the chemical, physical, and biological integrity of theNation's waters'' (Section 101(a), 33 U.S.C. 1251(a)). To achieve thisgoal, the CWA prohibits the discharge of pollutants into navigablewaters except in compliance with the statute. The Clean Water Actconfronts the problem of water pollution on a number of differentfronts. Its primary reliance, however, is on establishing restrictionson the types and amounts of pollutants discharged from variousindustrial, commercial, and public sources of wastewater.    Direct dischargers must comply with effluent limitations inNational Pollutant Discharge Elimination System (``NPDES'') permits;indirect dischargers must comply with pretreatment standards. Theselimitations and standards are established by regulation for categoriesof industrial dischargers and are based on the degree of control thatcan be achieved using various levels of pollution control technology.1. Best Practicable Control Technology Currently Available (BPT)--Section 304(b)(1) of the CWA    Section 304(b)(1)(A) of the CWA requires EPA to identify effluentreductions attainable through the application of, ``best practicablecontrol technology currently available for classes and categories ofpoint sources.'' Generally, EPA determines BPT effluent levels basedupon the average of the best existing performances by plants of varioussizes, ages, and unit processes within each industrial category orsubcategory. In industrial categories where present practices areuniformly inadequate, however, EPA may determine that BPT requireshigher levels of control than any currently in place if the technologyto achieve those levels can be practicably applied (see A LegislativeHistory of the Federal Water Pollution Control Act Amendments of 1972,U.S. Senate Committee of Public Works, Serial No. 93-1, January 1973,p. 1468).    In addition, CWA Section 304(b)(1)(B) requires a cost assessmentfor BPT limitations. In determining the BPT limits, EPA must considerthe total cost of treatment technologies in relation to the effluentreduction benefits achieved. This inquiry does not limit EPA's broaddiscretion to adopt BPT limitations that are achievable with availabletechnology unless the required additional reductions are ``wholly outof proportion to the costs of achieving such marginal level ofreduction.'' (see Legislative History, op. cit. p. 170). Moreover, theinquiry does not require the Agency to quantify benefits in monetaryterms (e.g., American Iron and Steel Institute v. EPA, 526 F. 2d 1027(3rd Cir., 1975)).    In balancing costs against the benefits of effluent reduction, EPAconsiders the volume and nature of expected discharges afterapplication of BPT, the general environmental effects of pollutants,and the cost and economic impacts of the required level of pollutioncontrol. In developing guidelines, the Act does not requireconsideration of water quality problems attributable to particularpoint sources, or water quality improvements in particular bodies ofwater.2. Best Available Technology Economically Achievable (BAT)--Section304(b)(2) of the CWA    The CWA establishes BAT as a principal means of controlling thedischarge of toxic and non-conventional pollutants. In general, BATeffluent limitations guidelines represent the best existingeconomically achievable performance of direct discharging plants in theindustrial subcategory or category. The factors considered in assessingBAT include the cost of achieving BAT effluent reductions, the age ofequipment and facilities involved, the processes employed, engineeringaspects of the control technology, potential process changes, non-waterquality environmental impacts (including energy requirements), and suchfactors as the Administrator deems appropriate. The Agency retainsconsiderable discretion in assigning the weight to be accorded to thesefactors. An additional statutory factor considered in setting BAT iseconomic achievability. Generally, the achievability is determined onthe basis of the total cost to the industrial subcategory and theoverall effect of the rule on the industry's financial health. BATlimitations may be based upon effluent reductions attainable throughchanges in a facility's processes and operations. As with BPT, whereexisting performance is uniformly inadequate, BAT may be based upontechnology transferred from a different subcategory within an industryor from another industrial category. BAT may be based upon processchanges or internal controls, even when these technologies are notcommon industry practice.3. Best Conventional Pollutant Control Technology (BCT)--Section304(b)(4) of the CWA    The 1977 amendments to the CWA required EPA to identify effluentreduction levels for conventional pollutants associated with BCTtechnology for discharges from existing industrial point sources. BCTis not an additional limitation, but replaces Best Available Technology(BAT) for control of conventional pollutants. In addition to otherfactors specified in section 304(b)(4)(B), the CWA requires that EPAestablish BCT limitations after consideration of a two part ``cost-reasonableness'' test. EPA explained its methodology for thedevelopment of BCT limitations in July 1986 (51 FR 24974).    Section 304(a)(4) designates the following as conventionalpollutants: biochemical oxygen demand (BOD5), totalsuspended solids (TSS), fecal coliform, pH, and any additionalpollutants defined by the Administrator as conventional. TheAdministrator designated oil and grease as an additional conventionalpollutant on July 30, 1979 (44 FR 44501).[[Page 6853]]4. New Source Performance Standards (NSPS)--Section 306 of the CWA    NSPS reflect effluent reductions that are achievable based on thebest available demonstrated control technology. New facilities have theopportunity to install the best and most efficient production processesand wastewater treatment technologies. As a result, NSPS shouldrepresent the greatest degree of effluent reduction attainable throughthe application of the best available demonstrated control technologyfor all pollutants (i.e., conventional, non-conventional, and prioritypollutants). In establishing NSPS, EPA is directed to take intoconsideration the cost of achieving the effluent reduction and any non-water quality environmental impacts and energy requirements.5. Pretreatment Standards for Existing Sources (PSES)--Section 307(b)of the CWA    PSES are designed to prevent the discharge of pollutants that passthrough, interfere with, or are otherwise incompatible with theoperation of publicly owned treatment works (POTWs). The CWA authorizesEPA to establish pretreatment standards for pollutants that passthrough POTWs or interfere with treatment processes or sludge disposalmethods at POTWs. Pretreatment standards are technology-based andanalogous to BAT effluent limitations guidelines.    The General Pretreatment Regulations, which set forth the frameworkfor implementing categorical pretreatment standards, are found at 40CFR part 403. Those regulations contain a definition of pass throughthat addresses localized rather than national instances of pass throughand establish pretreatment standards that apply to all non-domesticdischargers. See 52 FR 1586, January 14, 1987.6. Pretreatment Standards for New Sources (PSNS)--Section 307(b) of theCWA    Like PSES, PSNS are designed to prevent the discharges ofpollutants that pass through, interfere with, or are otherwiseincompatible with the operation of POTWs. PSNS are to be issued at thesame time as NSPS. New indirect dischargers have the opportunity toincorporate into their plants the best available demonstratedtechnologies. The Agency considers the same factors in promulgatingPSNS as it considers in promulgating NSPS.7. Best Management Practices (BMPs)    Sections 304(e), 308(a), 402(a), and 501(a) of the CWA authorizethe Administrator to prescribe BMPs as part of effluent limitationsguidelines and standards or as part of a permit. EPA's BMP regulationsare found at 40 CFR 122.44(k). Section 304(e) of the CWA authorizes EPAto include BMPs in effluent limitations guidelines for certain toxic orhazardous pollutants for the purpose of controlling ``plant siterunoff, spillage or leaks, sludge or waste disposal, and drainage fromraw material storage.'' Section 402(a)(1) and NPDES regulations (40 CFR122.44(k)) also provide for best management practices to control orabate the discharge of pollutants when numeric limitations andstandards are infeasible. In addition, section 402(a)(2), read inconcert with section 501(a), authorizes EPA to prescribe as wide arange of permit conditions as the Administrator deems appropriate inorder to ensure compliance with applicable effluent limitations andstandards and such other requirements as the Administrator deemsappropriate.8. CWA Section 304(m) Requirements    Section 304(m) of the CWA, added by the Water Quality Act of 1987,requires EPA to establish schedules for: (1) Reviewing and revisingexisting effluent limitations guidelines and standards; and (2)promulgating new effluent guidelines. On January 2, 1990, EPA publishedan Effluent Guidelines Plan (55 FR 80), in which schedules wereestablished for developing new and revised effluent guidelines forseveral industry categories, including the oil and gas extractionindustry. Natural Resources Defense Council, Inc., challenged theEffluent Guidelines Plan in a suit filed in the U.S. District Court forthe District of Columbia, (NRDC et al. v. Browner, 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'sproposal and promulgation of effluent guidelines for a number of pointsource categories. The most recent Effluent Guidelines Plan waspublished in the Federal Register on August 31, 2000 (65 FR 53008).This plan requires, among other things, that EPA take final actionregarding the Synthetic-Based Drilling Fluids Guidelines by December2000.B. Pollution Prevention Act    The Pollution Prevention Act of 1990 (PPA) (42 U.S.C. 13101 etseq., Public Law 101-508, November 5, 1990) ``declares it to be thenational policy of the United States that pollution should be preventedor reduced whenever feasible; pollution that cannot be prevented shouldbe recycled in an environmentally safe manner, whenever feasible;pollution that cannot be prevented or recycled should be treated in anenvironmentally safe manner whenever feasible; and disposal or releaseinto the environment should be employed only as a last resort * * *''(Sec. 6602; 42 U.S.C. 13101 (b)). In short, preventing pollution beforeit is created is preferable to trying to manage, treat or dispose of itafter it is created. The PPA directs the Agency to, among other things,``review regulations of the Agency prior and subsequent to theirproposal to determine their effect on source reduction'' (Sec. 6604; 42U.S.C. 13103(b)(2)). EPA reviewed this effluent guideline for itsincorporation of pollution prevention.    According to the PPA, source reduction reduces the generation andrelease of hazardous substances, pollutants, wastes, contaminants, orresiduals at the source, usually within a process. The term sourcereduction ``include(s) equipment or technology modifications, processor procedure modifications, reformulation or redesign of products,substitution of raw materials, and improvements in housekeeping,maintenance, training or inventory control. The term ``sourcereduction'' does not include any practice which alters the physical,chemical, or biological characteristics or the volume of a hazardoussubstance, pollutant, or contaminant through a process or activitywhich itself is not integral to or necessary for the production of aproduct or the providing of a service.'' 42 U.S.C. 13102(5). In effect,source reduction means reducing the amount of a pollutant that enters awaste stream or that is otherwise released into the environment priorto out-of-process recycling, treatment, or disposal.    In these final regulations, EPA supports pollution preventiontechnology by encouraging the appropriate use of synthetic-baseddrilling fluids (SBFs) based on the use of base fluid materials inplace of traditional: (1) Water-based drilling fluids (WBFs); and (2)oil-based drilling fluids (OBFs) consisting of diesel oil/or andmineral oil. The appropriate use of SBFs in place of WBFs willgenerally lead to more efficient and faster drilling and a per wellreduction in non-water quality environmental impacts (including energyrequirements) and discharged pollutants. Use of SBFs may also lead to areduced demand for new drilling rigs and platforms and development welldrilling though the use directional and extended reach drilling.Discharges from SBF-drilling operations have lower aqueous and[[Page 6854]]sediment toxicities, lower bioaccumulation potentials, and fasterbiodegradation rates as compared to OBFs. In addition, polynucleararomatic hydrocarbons (PAHs), including those which are prioritypollutants, which are constituents in OBFs are not present in SBFs.    EPA considered a ``zero discharge'' requirement (i.e., BAT/NSPSOption 3) for SBF-cuttings wastes and determined that under thisrequirement most operators would decrease the use of SBFs in favor ofOBFs and WBFs due to lower OBF and WBF drilling fluid unit costs. EPAconcluded that a zero discharge requirement for SBF-cuttings and thesubsequent increased use of OBFs and WBFs would result in: (1)Unacceptable non-water quality environmental impacts (NWQIs); and (2)more pollutant loadings to the ocean due to operators switching fromSBFs to less efficient WBFs.    The appropriate use of SBF in place of OBF will generally shortenthe length of the drilling project and eliminate the need to barge toshore or re-inject OBF-waste cuttings, thereby reducing NWQI such asfuel use, air emissions, and land disposal of OBFs. The controlleddischarge option also eliminates the risk of OBF and OBF-cuttingsspills and cross-media contamination at land disposal operations.Operators would be increasing the toxicity of their drilling fluids andwastes by using OBFs in place of SBFs. As stated in April 2000 (65 FR21557), EPA used SBF and OBF spill data in the final rule as a factorin supporting a controlled discharge option. U.S. Department ofInterior, Minerals Management Service (MMS) spill data show that riserdisconnects in deep water drilling can release approximately 2,400barrels of neat SBF and these incidences occur in deep water on averagetwo to three times per year due to riser failure (Docket No. W-98-26,Record No. IV.B.a.3). Riser disconnects in the deep water are aparticular concern due to: (1) Increased riser tensioning; (2) deepwater technical requirements (e.g., riser verticality, increased use oftop drive systems, multiple flex joints in riser, placement of wellheads and upper casing sections in soft sea beds); and (3) deep waterocean environments (e.g., uncharted eddy and loop currents) (Docket No.W-98-26, Record No. IV.B.a.4; Record No. IV.B.a.5). Use of WBFs inplace of SBFs would also lead to: (1) An increase in NWQIs due to theincreased length of the drilling project; and (2) a per well increasepollutants discharged due to poorer technical performance of WBFs. Forthese primary reasons, EPA rejected the zero discharge option.    In addition, the technology controls in the final regulation arebased on a more efficient solids control technology to increaserecycling of SBF in the drilling operation. Increased SBF recyclingreduces the quantity of SBF required for drilling operations and thequantity of SBF discharged with drill cuttings. A discussion of thispollution prevention technology is contained in Section V.A of thispreamble and in the SBF Development Document.C. Profile of Industry1. Well Drilling Process Description    The SBF Development Document presents a thorough description of theindustry including drilling practices, solids control systems, andwaste disposal operations. The following summary is excerpted from thattechnical document.    Drilling occurs in two phases: exploration and development.Exploration activities are those operations involving the drilling ofwells to locate hydrocarbon bearing formations and to determine thesize and production potential of hydrocarbon reserves. Developmentactivities involve the drilling of production wells once a hydrocarbonreserve has been discovered and delineated.    Drilling for oil and gas is generally performed by rotary drillingmethods which use a circularly rotating drill bit that grinds throughthe earth's crust as it descends. Drilling fluids are pumped downthrough the drill bit via a pipe that is connected to the bit, andserve to cool and lubricate the bit during drilling. The rock chipsthat are generated as the bit drills through the earth are termed``drill cuttings'' or simply ``cuttings.'' The drilling fluid alsoserves to transport the drill cuttings back up to the surface throughthe space between the drill pipe and the well wall (this space istermed the annulus), in addition to controlling downhole pressure andstabilizing the well bore.    As drilling progresses, large pipes called ``casing'' are insertedinto the well to line the well wall. Drilling continues until thehydrocarbon bearing formations are encountered. In areas where drillingfluids and drill cuttings are allowed to be discharged under thecurrent regulations, well depths range from approximately 4,000 to12,000 feet deep, and it takes approximately 20 to 60 days to completedrilling.    On the surface, the drilling fluid and drill cuttings undergo anextensive separation process to remove fluid from the cuttings. Thefluid is then recycled into the system, and the cuttings become a wasteproduct. The drill cuttings retain a certain amount of the drillingfluid that are discharged or disposed with the cuttings. Drill cuttingsare discharged by the shale shakers and other solids separationequipment (e.g., decanting centrifuges, mud cleaners, cuttings dryers).Drill cuttings are also cleaned out of the mud pits and from the solidseparation equipment during displacement of the drilling fluid system(i.e., accumulated solids). Intermittently during drilling, and at theend of the drilling process, drilling fluids may become wastes if theycan no longer be reused or recycled.    In the relatively new area of ultra-deep water drilling (i.e.,water depths greater than 3,000 feet), new drilling methods areevolving which can significantly improve drilling efficiencies andthereby reduce NWQIs (e.g., fuel, steel casing consumption, airemissions) and the per well amount of pollutants discharged. Subseadrilling fluid boosting, referred to as ``dual gradient drilling,'' isone such new drilling technology. Dual gradient drilling is similar totraditional rotary drilling methods as previously described with theexception that the drilling fluid is energized or boosted by use of apump at or near the seafloor. By boosting the drilling fluid, theadverse effect on the wellbore caused by the drilling fluid pressurefrom the seafloor to the surface is eliminated, thereby allowing wellsto be drilled with as much as a 50% reduction in the number of casingstrings generally required to line the well wall. As a result of thereduced number of casing strings, dual gradient wells can be drilledalmost one-third faster and with smaller hole sizes than conventionaldeep water drilling. Smaller hole sizes and faster drilling translateinto fewer pollutants being discharged to the ocean and fewer NWQI.Dual gradient drilling technology can also potentially eliminate orreduce the amount of whole drilling fluid released to the environmentduring an inadvertent riser disconnect. Finally, dual gradient drillingtechnology can greatly reduce the potential release of drilling fluidwhen drilling through shallow sand intervals (e.g., shallow water flow)(Docket No. W-98-26, Record No. IV.B.a.6).    Some dual gradient drilling systems require the separation of thelargest cuttings (e.g., larger than approximately \1/4\ inch) at theseafloor since these cuttings may interfere with the rotatory action ofsubsea pumps (e.g., electrical[[Page 6855]]submersible pumps). The larger cuttings are routed at the seafloor to aventuri action pump (with no moving parts), mixed with seawater, andpumped to a cuttings discharge hose at the seafloor within a 300 footradius of the well site. The hose is perforated on the last 50 ft ofits length to maximize the spread of cuttings. The action of pumpingcuttings with seawater can be expected to have some cleaning anddispersion effect. A remotely operated vehicle (ROV) can also be usedto reposition the subsea discharge hose to maximize cuttings dispersal.Representative samples of drill cuttings discharged at the seafloor canbe transported to the surface by a ROV for purposes of monitoring. Thedrilling fluid, which is boosted at the seafloor and transports most ofthe drill cuttings (e.g., 95-98% of total cuttings generated) back tothe surface, is processed as described in the general rotary drillingmethods described above in this section.    A commercial potential determination is made at the completion ofrotary drilling (i.e., once the target oil or natural gas formationshave been reached). The well is then made ready for production by aprocess termed ``completion.'' Completion involves cleaning the well toremove drilling fluids and debris, perforating the casing that linesthe producing formation, inserting production tubing to transport thehydrocarbon fluids to the surface, and installing the surface wellhead.The well is then ready for production (i.e., actual extraction ofhydrocarbons).2. Location and Activity    This rule establishes effluent limitations guidelines and standardsthat control discharges of SBF and SBF-cuttings throughout the Offshoresubcategory beyond three miles from shore, except for Offshore Alaskawhere no three mile restriction applies. This rule prohibits dischargeof SBF and SBF-cuttings in Upper (Coastal Subcategory) Cook Inlet,Alaska, unless operators meet criteria demonstrating that they areunable to: (1) Box and store their cuttings on-site for zero dischargecuttings transfer operations (i.e., haul to shore for land disposal orre-injection at another rig or platform); or (2) re-inject their SBF-cuttings on-site. When Coastal Cook Inlet, AK, operators demonstrate tothe NPDES controlling authority that they are unable to achieve zerodischarge of their SBF-cuttings, they may discharge their SBF-cuttingsunder the same controls as exist for SBF-cuttings discharges inOffshore waters. Criteria for establishing when operators cannotachieve zero discharge are established in the final regulation. SBF-cuttings discharged in Offshore Cook Inlet, Alaska, are controlled inthe same manner as other SBF-cuttings in other Offshore waters. Thisrule does not amend the requirements for zero discharge of drillingfluids and drill cuttings where they have already been prohibited fromdischarge.    Drilling is currently active in three regions: (1) The offshorewaters beyond three miles from shore in the Gulf of Mexico (GOM); (2)offshore waters beyond three miles from shore in California; and (3)Cook Inlet, Alaska. Most drilling activity occurs in the GOM, where1,302 wells were drilled in 1997, compared to 28 wells drilled inCalifornia and 7 wells drilled in Cook Inlet. In the GOM, over the lastfew years, there has been high growth in the number of wells drilled indeep water (e.g., water depths greater than 1,000 feet). For example,in 1995, 84 wells were drilled in deep water, comprising 8.6% of allGOM wells drilled that year. By 1997, that number increased to 173 deepwater wells drilled and comprised over 13% of all GOM wells drilled.Most recent 1999 data show that this trend is continuing as over 15% ofall GOM wells drilled were in deep water. The increased activity indeep water increases the usefulness of SBFs. Operators drilling in deepwater cite the following factors for selecting SBFs over WBFs and OBFs:(1) Potential for riser disconnect (i.e., inadvertent releases ofdrilling fluid) in floating drill ships, which favors SBF over OBF; (2)higher daily drilling cost which more easily justifies use of moreexpensive SBFs over WBFs; and (3) greater distance to barge drillingwastes that may not be discharged (i.e., OBFs, WBFs that fail the SPPToxicity Test as currently required by EPA in Appendix 2 to Subpart Aof 40 CFR part 435).3. Drilling Wastestreams    Drilling fluids and drill cuttings are a major source of waste fromexploratory and development well drilling operations. This finalregulation establishes limitations for both the drilling fluid and thedrill cuttings wastestream when SBFs are used. All other wastestreamsand drilling fluids(e.g., WBFs, OBFs) already have limitations; those limitations areoutside the scope of this rule. The characteristics of both drillingfluids and drill cuttings wastestreams are summarized in Section V.A ofthis preamble. A more detailed discussion of the origins andcharacteristics of these wastes is also included in the SBF DevelopmentDocument.D. Proposed Rule    On February 3, 1999 (64 FR 5488), EPA published proposed effluentlimitations guidelines for the discharge of SBF drilling fluids anddrill cuttings into waters of the United States by existing and newfacilities in the oil and gas extraction point source category.    EPA received comments on many aspects of the proposal. The majorityof comments related to: (1) The proposed analytical test methods forstock and discharge limitations; (2) equipment used to set BAT and NSPScuttings retention limitations; (3) Best Management Practices (BMPs)and their use to control small volume spills and releases of SBF; (4)the proposal's engineering and economic modeling parameters; and (5)procedural and definition issues. EPA evaluated all of these issuesbased on additional information collected by EPA or received during thecomment period. EPA then discussed the results of these evaluations ina Notice of Data Availability which is discussed below.E. Notice of Data Availability    On April 21, 2000 (65 FR 21548), EPA published a Notice of DataAvailability (NODA) to present a summary of new data received incomments on the proposed rule or collected by EPA following publicationof the proposal. In the April 2000 NODA, EPA discussed the major issuesand presented several revised modeling and alternative approaches toaddress these issues. EPA solicited comment on the data collected sinceproposal and on the revised modeling and alternative approaches tomanage SBF discharges.III. Summary of Data and Information Received in Response to theNotice of Data Availability    The April 2000 NODA summarized the data and information received byEPA in response to the February 1999 proposal and information receivedbefore the April 2000 NODA. This section describes the data received byEPA in response to the April 2000 NODA.A. Pollutant Loading and Numeric Limit Analyses1. SBF Retention on Cuttings    SBF retention on cuttings (ROC) data quantify the amount of SBFretained on cuttings (mass of SBF/mass of wet cuttings, expressed as apercentage). Lower ROC values indicate less SBF retained on cuttings.EPA uses ROC data, along with other engineering factors (e.g.,installation requirements, fluid rheology) to evaluate the[[Page 6856]]performance of various solids control technologies.    In response to the February 1999 proposal, industry submitted datafor SBF ROC from 36 wells. EPA determined that 16 files were completeand accurate, and these data were presented in the April 2000 NODA. EPArejected six files due to incomplete reporting. EPA received 14 filestoo late for inclusion in the April 2000 NODA analyses.    In response to the April 2000 NODA, EPA received and evaluated ROCdata from an additional 79 SBF wells: the 14 received after theFebruary 1999 proposal comment period; 27 additional sets receivedduring the April 2000 NODA comment period; and 38 received after theApril 2000 NODA comment period. EPA determined that data from 49 ofthese 79 wells were complete for inclusion in the final rule analyses.Therefore, EPA used data from 65 wells to determine the ROC performanceof the various solids control technologies. The collection, engineeringreview, and extraction of data from these files are described in theSBF Development Document.    EPA revised the average ROC values of various solids controltechnologies based on the final ROC data. These revised average ROCvalues were combined to yield the average ROC value for the followingthree SBF-cuttings technology options: (1) BAT/NSPS Option 1 is basedon the use of shale shakes, cuttings dryer, fines removal unit, anddischarges from the cuttings dryer and fines removal unit and has along-term average ROC value of 4.03%; (2) BAT/NSPS Option 2 is based onthe use of shale shakes, cuttings dryer, and fines removal unit, andone discharge from the cuttings dryer, and has a long-term average ROCvalue of 3.82%; and (3) BAT/NSPS Option 3 is based on the use of shaleshakes, cuttings boxes, barges, and zero discharge land disposal andoffshore re-injection and has a long-term average ROC value of 10.2%.In addition, using the ROC data, EPA developed a BAT limitation andstandard controlling the base fluid retained on cuttings for drillingfluids with the environmental performance of esters (e.g.,biodegradation, sediment toxicity). EPA developed this option toprovide operators an incentive to use ester-based SBFs and has a long-term average ROC value of 4.8%. EPA used the ROC data to establish aBAT limitation and a NSPS on base fluid retained on cuttings. The basefluid retained on cuttings limitation and standard both incorporate thevariability of solids control efficiencies and are higher than the longterm average.2. Days to Drill    EPA uses the number of days to drill the SBF interval, for all fourmodel wells, as an input parameter in the NWQI and cost analysis. EPAextracted relevant data from each of the 65 wells identified above toestimate the number of days to drill each of the four model well SBFintervals (Docket No. W-98-26, Record No. IV.B.a.7). The revisednumbers of days required to drill the SBF model wells are based on arevised average rate of SBF-cuttings generation (i.e., 108.7 bbls wetcuttings/day). The revised numbers of days required to drill the SBFmodel wells are: (1) 5.2 days for shallow-water development wells(SWD); (2) 10.9 days for shallow-water exploratory wells (SWE); (3) 7.9days for deep-water development wells (DWD); and (4) 17.5 days fordeep-water exploratory wells (DWE).3. Well Count Projections Over Next Five Years    EPA revised well count projections for Offshore GOM, OffshoreCalifornia, and Cook Inlet, AK, based on information submitted byindustry (Docket No. W-98-26, Record No. IV.B.a.9; Record No.IV.B.a.10; Record No. IV.B.a.11). The revised annual well counts are1,047 shallow water wells and 138 deep water wells in Offshore GOM; 7shallow water wells and no deep water wells in Offshore California; and6 shallow water wells and no deep water wells in Cook Inlet, AK. Theserevised well counts are not significantly different from the wellcounts used in the February 1999 proposal and April 2000 NODA (i.e.,see SBF Proposal Development Document (EPA-821-B-98-021), Table IV-2:1,022 shallow water wells and 139 deep water wells across the GOM,Offshore California, and Cook Inlet, AK).    Industry only provided the well counts in terms of shallow waterversus deep water wells. EPA further divided the revised well countsinto development and exploratory well category counts for estimatingpollutant loadings, compliance costs, and NWQIs. EPA performed thisallocation using prior well count data from the April 2000 NODA. EPAderived percentages of development versus exploratory wells for bothshallow water well types and deep water well types. EPA then appliedthese percentages to the revised aggregated shallow water and deepwater well counts provided by industry. EPA also collected additionalwashout rates for WBF and SBF drilling.    EPA also revised well count projections to reflect enhanceddirectional drilling capabilities when using SBF. EPA receivedinformation that SBF directional drilling can reduce the number ofwells required to drill a development well project. Specifically,industry stated that SBF development drilling can generally reduce thedrilled footage required for full development of a typical reservoir byone-third as compared with WBF drilling (Docket No. W-98-26, Record No.IV.B.a.9). EPA has included this consideration by reducing the footagedrilled by one-third for WBF development wells projected to convertfrom WBF to SBF under the two controlled discharge options.4. Current and Projected OBF, WBF, and SBF Use Ratios    For the February 1999 proposal and April 2000 NODA, EPA estimatedthat 80% of the average annual GOM wells are drilled using WBFexclusively; 10% are drilled with SBF; and 10% are drilled with OBF.EPA also included in well counts estimates of operators converting fromOBF to SBF or SBF to OBF under each of the SBF-cuttings controlleddischarge options.    For the final rule, EPA revised the relative frequency of usebetween WBF, OBF, and SBF under the two discharge options and the zerodischarge option based on data submitted by industry (Docket No. W-98-26, Record No. IV.B.a.9; Record No. IV.B.a.10; Record No. IV.B.a.11).Industry supplied this information to EPA in several formats. EPA usedthe most reliable information (e.g., the actual well count data forWBF, OBF, and SBF wells over a period of three years) to estimatedrilling fluid use under each of the SBF-cuttings control options (seeSBF Development Document).    EPA believes that some operators would switch from WBFs to SBFs forcertain wells due to the increased efficiency of SBF drilling. While nogood industry average statistics exist, it is generally considered thatSBFs reduce overall drilling time by 50% (e.g., if a well took 60 daysto drill with WBF, the same well should be able to be drilled with SBFin 30 days) (Docket No. W-98-26, Record No. IV.B.a.9; Record No.IV.B.a.10; Record No. IV.B.a.11). Reducing drilling time generallyreduces drilling costs. However, not all drilling operators will switchfrom WBFs to SBF due to a variety of other factors, (e.g., WBFs areless expensive (per barrel) than SBFs, potential for lost circulationdownhole).    Additionally, EPA believes that under the SBF-cuttings zerodischarge option, not all operators would switch from[[Page 6857]]SBFs to OBFs but that some operators would switch to WBFs. Somedrilling operations require the technical performance of non-aqueousdrilling fluids and operators must select either an OBF or SBF.Therefore, for these drilling operations, operators would select OBFsin place of SBF under the SBF-cuttings zero discharge option as OBFsare less expensive (per barrel) than SBFs. However, some drillingoperations could use either WBFs or oleaginous drilling fluids such asOBFs, enhanced mineral oil based drilling fluids, or SBFs. Depending ona variety of site specific factors (e.g., formation characteristics,directional drilling requirements, torque and drag requirements),operators may select WBFs in lieu of SBFs or OBFs under the SBF-cuttings zero discharge option.5. Waste Volumes and Characteristics    EPA collected additional data to identify the volumes andcharacteristics of WBF discharges. This additional data more adequatelydescribes the total amount of pollutants loadings and NWQI under eachof the three SBF-cuttings management options. For example, under theSBF zero discharge option (BAT/NSPS Option 3) operators would morelikely choose WBF and OBF over SBF due primarily to the relativelyhigher unit cost of SBF.    Different pollutant loadings and NWQI are expected for WBF ascompared with either OBF or SBF wells based on differences in washoutand length of drilling time. EPA anticipates a reduction in cuttingswaste volume when comparing SBF-drilling to WBF-drilling based ongreater hole washout (i.e., enlargement) in WBF drilling. Industryestimated that WBF washout percentages vary between 25% and 75%, with45% being an acceptable average and confirmed EPA's SBF and OBF washoutpercentage of 7.5% as appropriate (Docket No. W-98-26, Record No.IV.B.a.9).    For the final rule, EPA also estimated that the barite used in SBFdrilling is nearly pure barium sulfate (i.e., BaSO4) and, bygravimetric analysis, calculated the weight percentage of barium inbarite as 58.8%.B. Compliance Costs Analyses1. Equipment Installation and Downtime    For the April 2000 NODA, projected compliance costs for all optionsincluded equipment installation and downtime for each SBF well drilled.After further review of ROC data wells (see Section III.A), EPAmodified this parameter in the final analyses to reflect currentpractice of drilling multiple wells per year for any one equipmentinstallation (Docket No. W-98-26, Record No. IV.B.a.9). EPA reviewedthe ROC well data for the frequency of multiple wells on specifiedstructures. EPA used the resulting well-per-structure analysis toadjust projected annual SBF compliance costs by including theconsideration of drilling more than one SBF well per equipmentinstallation per year. EPA estimated that 2.2 development wells perstructure and 1.6 exploratory wells per structure are current industrypractice, based on industry-submitted data (see SBF DevelopmentDocument).    EPA received information on the ability of operators to installcuttings dryers (e.g., vertical or horizontal centrifuges, squeezepress mud recovery units, High-G linear shakers) on existing GOM rigs(Docket No. W-98-26, Record No. IV.B.b.33). While some industry sourcesfiled timely comments alleging that some rigs could not accommodateadditional solids control equipment, in late comments, industryprovided data concerning the number of GOM rigs in operation which arenot capable of having a cuttings dryer system installed due to eitherrig space and/or rig design without prohibitive costs or rigmodifications.    EPA also received information on a new cuttings containment,handling, and transfer equipment system. The new system is designed toeliminate the need to use cuttings boxes to handle cuttings. EPAreceived information from one operator that recently field tested thecuttings transfer system on one 12\1/4\ inch well section in the NorthSea. The operator contained 100% of the cuttings on a rig (Alba) withlimited deck space. Cuttings were handled in bulk below deck and pumpeddirectly onto a waiting vessel for eventual land disposal. The operatorestimated that use of the new cuttings transfer system eliminatedhundreds of crane lifts and manual handling issues and thereby improvedworker safety.2. Current Drilling Fluid Costs    In response to the April 2000 NODA, EPA revised unit costs of WBF,OBF, and SBF. Based on industry data, EPA used the WBF unit cost of $45per barrel for the final rule. The February 1999 Proposal and April2000 NODA used OBF and SBF unit costs of $75 and $200 per barrel ofdrilling fluid, respectively. Industry data indicates a range of OBFunit costs from $70-$90 per barrel and EPA used the OBF unit cost of$79 per barrel for the final rule. EPA estimates that SBF unit costswill remain between $160 to $300 per barrel of drilling fluid over thenext few years. EPA used an SBF unit cost of $221 per barrel ofdrilling fluid for the final rule based on the most frequently used SBFin the offshore market.3. Cost Savings of SBF Use as Compared With WBF Use    EPA revised its compliance costs to include the following factors:(1) The cost savings associated with increased rate of penetration whenusing SBF as compared to WBF; and (2) the cost of lost WBFs that aredischarged while drilling. EPA also examined, but did not include inits final compliance cost impacts, the costs associated with projectedfailures of a fraction of WBF wells to meet sheen or toxicitylimitations, including costs of meeting zero discharge from thesewells. EPA used this data to examine compliance costs impacts ifoperators switch from SBF to WBF drilling, or vice versa.    EPA requested data from industry on rate of penetration (ROP) forWBF operations as compared to SBF operations. Industry stated that ROPvalues of 300 feet per hour for SBF (and OBF) operations and 150 feetper hour for WBF are reasonable averages. However, using these valuesover an entire well was not recommended ``due to the large number ofvariables'' (Docket No. W-98-26, Record No. IV.B.a.9). Industry'sinformation further states that a generally-accepted estimate is that``SBFs reduce overall drilling time by 50%'' (Docket No. W-98-26,Record No. IV.B.a.9).4. Construction Cost Index    EPA used the Construction Cost Index (CCI) from the EngineeringNews and Record (see http://www.enr.com/cost/costcci.asp) to reflectcosts in 1999 dollars rather than 1998 dollars as was used for theApril 2000 NODA. EPA used a CCI factor of 1.108 to reflect 1999 dollarsand a base year of 1995.C. Economic Impacts Analyses    For the final rule, EPA obtained and used MMS data on drillingthrough 1999 to identify any new firms operating in the offshore GOMand determine which firms were involved in deep water drillingoperations. EPA identified 17 additional firms newly drilling in theGOM, of which 2 were identified as drilling in deep water. Of the newfirms, 7 were identified as or assumed to be (for lack of data) smallentities. One of these seven small firms was identified as a smallentity drilling in deep water. This latter firm drilled two wells inthe deep water in 1999.    EPA collected 1999 financial information on number of employees,[[Page 6858]]assets, equity, revenues, net income, return on assets, return onequity, and profit margin for the publicly held, newly identifiedfirms. EPA also updated financial information for the publicly heldfirms identified in February 1999 proposal SBF Economic Analysis (EPA-821-B-98-020).    EPA also collected information on 13 GOM onshore sites whereoffshore oil and gas drilling waste is handled or disposed. Thisinformation consists of precise geographical location, amount of wastehandled annually, and site capacity. This information was provided toEPA Region 6 for use in its environmental justice (EJ) computer modelto screen for sites (i.e., Tier 1 analysis) where disposal ofadditional drilling wastes under a zero discharge option might haveenvironmental justice implications. EPA Tier 1 analyses identified thatfive of the thirteen onshore facilities warranted additional review.D. Water Quality Impact and Human Health Analyses    In response to April 2000 NODA comments and information, EPArevised the water quality and human health analyses for the final rulebased on: (1) Information on seabed surveys; (2) revised fishconsumption rates; (3) information on Alaska state water qualitystandards; and (4) revised ROC data which affect EPA modeling of waterquality, sediment quality, and human health impacts.1. Seabed Surveys    EPA received public comments regarding the impact of SBF dischargeson the benthic environment. Several seabed surveys were submitted toEPA together with the public comments. Information from two commentscontained specific seabed survey data on sediment SBF concentrationsafter discharge of SBF cuttings. EPA included additional data from sixwells in the calculation of mean SBF sediment concentration (at 100meters from the modeled discharge) used in the water quality analysis.The mean SBF sediment concentration changed from 14,741 mg/kg aspublished in the April 2000 NODA to 9,718 mg/kg for modeled Gulf ofMexico wells and from 8,655 mg/kg to 13,052 mg/kg for wells modeled inOffshore California and Cook Inlet, Alaska.    EPA also received information on the on-going joint Industry/MMSGOM seabed survey. The Industry/MMS workgroup completed the first twocruises of the four cruise study in time for EPA's consideration forthis final rule. Cruise 1 was a physical survey of 10 GOM shelflocations, with the objective of detection and delineation of cuttingspiles using physical techniques. Cruise 2 was to scout and screen thefinal 5 shelf and 3 deep water GOM wells chosen for the definitivestudy where SBF were used. The SBF-cuttings discharges included eitherinternal olefins or LAO/ester blends. Both cruises did not detect anylarge mounds of cuttings under any of the rigs or platforms. Remotelyoperated vehicles (ROV) using video cameras and side-scanning sonarwere used to conduct the physical investigations on the seabed. Videoinvestigations only detected small cuttings clumps (6") around the baseof some of the facilities and 1" thick cuttings accumulations onfacility horizontal cross members. Outside of a 50-100' radius from thefacility, no visible cuttings accumulations (large or small) weredetected at any of the facility survey sites.    Finally, EPA received a report prepared for the MMS which provideda review of the scientific literature and seabed surveys to determinethe environmental impacts of SBFs (Docket No. W-98-26, Record No.IV.F.1). The literature report confirms EPA's position that benthiccommunities will recover as SBF concentrations in sediments decreaseand sediment oxygen concentrations increase. The report also confirmsEPA's position that within three to five years of cessation of SBF-cuttings discharges, concentrations of SBFs in sediments will havefallen to low enough levels and oxygen concentrations will haveincreased enough throughout the previously affected area that completerecovery will be possible.2. Fish Consumption Rates    EPA revised the fish consumption rates for use in environmentalassessment analyses. The consumption rates vary depending on the fishhabitat location (i.e., freshwater, estuarine, and marine). EPA usedthe marine only fish consumption rate for the finfish consumptionhealth risk analysis for the Gulf of Mexico and Offshore California.EPA used the estuarine/marine consumption rate for the Cook Inlet,Alaska analysis. EPA used the estuarine/marine consumption rate for allregions in the shrimp consumption health risk analysis.    EPA also conducted an investigation into the environmental factorsaffecting Native subsistence foods in Cook Inlet. EPA has incorporatedrelevant information from this investigation into the SBF EnvironmentalAssessment.3. State Water Quality Standards    EPA evaluated the potential decrease of water quality from theregulatory discharge options and compared the pollutant concentrationsto recommended Federal water quality criteria. For discharges occurringin Cook Inlet, Alaska, EPA also compared the receiving water quality toAlaska state water quality standards. EPA used the updated Alaska statestandards for the water quality analysis for Cook Inlet, Alaska.E. Non-Water Quality Environmental Impact Analyses    EPA received additional data affecting the NWQI analyses inresponse to the April 2000 NODA. These data include additionalinformation on retention on cuttings and information regarding offshoreinjection and onshore disposal practices for each of the threegeographical areas: Gulf of Mexico, Offshore California, and CookInlet, Alaska.    EPA revised the average SBF retention on cuttings for the dischargeoptions based on additional ROC data. Revisions in ROC data affect thevolume of SBF-cuttings generated. Consequently, EPA revised the amountof SBF-cuttings that will need to be treated under the two SBF-cuttingscontrolled discharge options (e.g., BAT/NSPS Options 1 and 2). EPA alsorevised: (1) The amount of SBF-fines that will need to be re-injectedon-site or hauled to shore for disposal under one of the SBF-cuttingscontrolled discharge option (e.g., BAT/NSPS Option 2); and (2) theamount of SBF-fines and SBF-cuttings re-injected on-site or hauled toshore for disposal under the zero discharge option (BAT/NSPS Option 3).    EPA received additional SBF well interval data which was used tore-calculate the number of days to drill the model SBF wells (seeSection III.B.). For the NWQI analyses, the number of days to drill themodel wells serves as the basis for estimating the length of timeequipment will be used to either treat the cuttings before discharge orthe hauling requirements under the zero discharge option. The EPA NWQImodels estimate that air emissions and fuel use rates increase when thetime required to complete a model well also increases.    EPA obtained information regarding the current practice of zerodischarge disposal for each of three geographic areas, Gulf of Mexico,Offshore California, and Cook Inlet, Alaska (see Section IV.D). Currentpractice indicates that most of the waste generated in the Gulf ofMexico and Offshore California[[Page 6859]]and brought to shore is injected onshore, whereas all of the wastecurrently generated in Cook Inlet is injected offshore at the drillingsite or at a near-by Class II Underground Injection Control (UIC)disposal well. EPA also received from an on-shore injection facilityspecific equipment information, including the cuttings injection rateand cuttings grinding and injection equipment power requirements andfuel rates (Docket No. W-98-26, Record No. IV.D.2).    Industry provided EPA with information regarding SBF use (seeSection III.A). One operator (Unocal) stated that it is starting to useSBF to drill the entire well and not just intervals in which WBFspresent problems because drilling time can be significantly reduced.EPA incorporated this information into the NWQI analyses by estimatingthe reduction of impacts when using SBFs instead of WBFs. EPA alsoreceived during the April 2000 NODA comment period information relatedto the average increase in drilling time (1.5 days) in order to complywith zero discharge (Docket No. W-98-26, Record No. IV.A.a.3).F. Compliance Analytical Methods    EPA completed additional studies in response to the April 2000 NODAto support the development of analytical methods for determiningsediment toxicity, biodegradation, and oil retention on cuttings. Forsediment toxicity and biodegradation, EPA focused specifically onoptimizing test conditions (e.g., test duration, sediment composition),discriminatory power, reproducibility, reliability, and practicality.EPA's sediment toxicity study provided toxicity data for both pure basefluids and standard mud formulations of these base fluids. EPA'sbiodegradation study evaluated the degradation of pure base fluids asdetermined by the solid phase test. For oil retention on cuttings, EPAconducted studies to verify and document the sensitivity of the retorttest method.    During this same time period, industry sponsored Synthetic BasedMuds Research Consortium (SBMRC) conducted parallel studies on the samethree parameters (i.e., sediment toxicity, biodegradation, and basefluid retention on cuttings). For sediment toxicity, industry providedextensive data comparing a 4-day versus a 10-day test duration, naturalversus synthetic sediments, as well as toxicity data on both pure basefluids and mud formulations of these base fluids. For biodegradation,industry submitted results from the closed bottle and respirometrytests for biodegradation in addition to the solid phase test. For oilretention on cuttings, Industry and EPA conducted rig-based methoddetection limit studies.IV. Summary of Revisions Based on Notice of Data AvailabilityComments    A summary of significant revisions to the analyses made by EPA inresponse to the February 1999 proposal is provided in the April 2000NODA (see 65 FR 21549, Sections III and IV). This section describes therevisions to the analyses since publication of the April 2000 NODA.A. Pollutant Loading Analyses1. Loadings for Water-Based Drilling Fluids and Cuttings    For the final rule, EPA included the pollutant reductions (orincreases) of the technology options based on operators switching fromOBFs or WBFs to SBFs (or vice versa) and used data contained in theOffshore Development Document (EPA-821-R-93-003). Waste volume and/orpollutant loading data, on use of OBFs and WBFs presented in theOffshore Development Document, were expressed on a ``per bbl,'' ``perwell,'' or a ``per day'' basis. Data from the Offshore rule recordincluded: (1) WBF composition; (2) waste volumes for WBFs, OBFs, andassociated cuttings; (3) the frequency of mineral oil use in WBFoperations; and (4) the expected permit limitation failure rates(primarily for toxicity) on mineral oil fluids resulting in therequirement to haul or inject these wastes). These data then wereapplied to the current, revised well count projections and/or projectedwaste volumes to estimate discharge option loadings and the amount ofOBFs, WBFs, and associated cuttings that require zero discharge underexisting regulations (e.g., OBFs containing diesel oil, WBFs that failthe SPP Toxicity Test). The Offshore Development Document providedinformation relevant to the inclusion of WBFs in the final analysesincluding: (1) Frequency of WBFs that failed permit limitations (TablesXI-10 and XI-7); (2) the composition of WBFs (Tables XI-3 and XI-6);(3) mineral oil composition (Table XI-5); and (4) the composition ofcuttings from WBF (Section XI.3.4).    Industry-wide, regional, and total loadings were calculated for theloadings analyses for this final rule from the revised well countsprovided by industry (Docket No. W-98-26, Record No. IV.B.a.9; RecordNo. IV.B.a.10; Record No. IV.B.a.11) combined with composition andestimated discharge volumes for WBFs (Offshore Development Document,Table XI-2).    In the final loadings analyses, EPA also corrected an error in theloading model used for the April 2000 NODA analyses. The error relatedto how EPA estimated the volume of fines from the fines removal unitcaptured and not discharged under BAT/NSPS Option 2. The volume offines is based on many factors including the hole size, washout, andthe percentage of the total wet cuttings produced from the solidscontrol system that are fines. EPA incorrectly used the volume of drycuttings per model well in the April 2000 NODA loading model toestimate the volume of fines generated from the BAT/NSPS Option 2solids control system. The final loadings model correctly uses thevolume of wet cuttings per model well to estimate the volume of finesgenerated from the BAT/NSPS Option 2 solids control system. Thecorrection of the error had the effect of increasing the amount offines captured for zero discharge under BAT/NSPS Option 2.2. Drilling Fluid and Cuttings Composition and Density    The density of drilling wastes hauled in California was revisedfrom 704 to 716 pounds per barrel to reflect the current densityderived from the weight and volume data in the revised loadings model.This results in a change in the unit cost to haul waste in Californiato $12.53 and $5.89 per barrel for disposal and handling costs,respectively.3. Days to Drill    EPA revised the number of drilling days based on data submitted inresponse to the April 2000 NODA for each of the four model well types.The number of drilling days input parameter affects NWQI and compliancecosts (e.g., equipment rental costs).4. Directional Drilling    EPA also received additional data concerning the performance of SBFversus WBF for directional drilling operations (Docket No. W-98-26,Record No. IV.B.a.9). EPA used this information, the reduced number ofwells and total footage of SBF-drilled development wells, to estimatepollutant loading reductions resulting from WBF to SBF conversions. Foreach of the two SBF-cuttings controlled discharge options (i.e., BAT/NSPS Option 1 and 2), this revision reduced the annual sum total ofdischarged WBF and WBF-cuttings.[[Page 6860]]B. Compliance Cost Analysis1. Costs of WBF    As stated above, EPA modified the cost analysis for the final ruleto include WBF cost factors. The WBF cost factors that EPA consideredinclude: (1) The cost of discharged WBFs and WBF associated withcuttings discharged onsite; (2) the projected occurrence of mineral oilspots and/or lubrication and the projected failure rate of thesemineral oil-amended fluids to meet permit limitations on toxicity andsubsequent requirement to re-inject these materials down hole or haulthem for onshore disposal; and (3) the rig costs associated withincreases or decreases of drilling time related to WBF-to-SBF or SBF-to-WBF conversions over the projected interval of SBF use.    The volumes of discharged WBF and associated cuttings wereestimated on a per well basis from data contained in the OffshoreDevelopment Document (EPA-821-R-93-003) for Gulf of Mexico, California,and Cook Inlet, AK wells. A weighted average discharge volume for eachregion, based on volumes projected for shallow wells and deep wells andthe projected number of wells for each, was derived to estimate thevolume of fluids and cuttings discharged onsite, per well, from WBFoperations. (Note: In the Offshore Development Document ``shallow'' and``deep'' refer to well depth, and are not the same as ``shallow'' waterand ``deep'' water wells which refer to water depth in this finalrule.) The volume of adhering WBF on discharged cuttings, as containedin the Offshore Development Document, was estimated at 5% of the totalcuttings volume. The costs for these discharged WBFs were thencalculated from a per barrel estimate of average WBF cost. These perwell costs were then applied to the well count data in this final ruleto derive aggregate regional and total costs. Also, to assess lostfluid costs over the projected SBF drilling interval, for the zerodischarge option, the average discharge volumes per well wererecalculated as average discharge volumes per day, based on the assumednumber of days (i.e., 20 days) used in the Offshore DevelopmentDocument for drilling WBF wells.    The projected incidences of WBF with mineral oil spots, mineral oillubrication, or both mineral oil spot and lubrication were based on theOffshore Development Document estimates of the percentages of projectedwells in each region, projected shallow water versus deep water wells,and the projected incidence of spotting and lubrication. Thesepercentages were then applied to current well count data for this finalrule. EPA used the Offshore Development Document rates of failure(i.e., exceeding permit toxicity limitations) to project the currentnumber of wells that would require onsite injection or onshore disposalof mineral oil-amended WBF, and their disposal volumes were calculatedfrom per well volume estimates for WBF wells.    The effect of WBF-to-SBF conversion (anticipated under thedischarge options) and SBF-to-WBF conversion (anticipated under thezero discharge option) were derived from the estimated duration (indays) of the SBF-drilled interval. The projected number of drillingdays was increased by a factor of 2 for each WBF model well to derivethe projected number of drilling days that would be required if WBFswere used in place of SBFs. The incremental drilling time was used toestimate compliance costs (e.g., increased rig costs) associated withSBF-to-WBF conversions.2. Equipment Installation and Downtime    In the April 2000 NODA, EPA estimated that each SBF well incurredcuttings dryer installation and downtime costs. EPA revised the numberof SBF wells drilled per cuttings dryer equipment installation per yearbased on industry-supplied ROC data (see Section III.B.1). EPAconcluded that operators are drilling multiple wells per year with thesame cuttings dryer equipment installation. Consequently, EPA reducedthe number of cuttings dryer equipment installations required to drillthe annual number of SBF wells. For development wells, the averagenumber of SBF wells drilled per cuttings dryer equipment installationper year is 2.2. For exploration wells, the average number of SBF wellsdrilled per cuttings dryer equipment installation per year is 1.6. EPAincorporated these factors into the compliance costs estimates andthese factors reduced the overall cuttings dryer equipment installationand downtime costs for the industry.3. Proportion of Hauled Versus Injected Wastes    EPA estimated in the April 2000 NODA that 80% of drillingoperations in the GOM, Offshore California, and Cook Inlet, Alaska,haul waste onshore with the remaining 20% re-injecting these wastesonsite. EPA used these proportions to weight the average cost ofcomplying with zero discharge (i.e., BAT/NSPS Option 3). EPA revisedthese proportions based on additional information received in responseto the April 2000 NODA (see Section IV.E below) and updated thecompliance cost and NWQI models.4. OBF and WBF Conversion to SBF    EPA revised its compliance cost model to incorporate the effect ofoperators switching from one type of drilling fluid to another undereach of the three SBF-cuttings technology options (see SectionIII.A.4). Generally, as compared with WBF and OBFs, SBFs led to areduction in days required to drill a model well which leads to adecrease in drilling costs. Additionally, EPA revised the developmentdrilling footage estimate due to additional information on the improveddirectional drilling capabilities of SBF over WBF.C. Economic Impacts Analyses    In response to the April 2000 NODA, EPA identified that twoprojects used for economic modeling have shut in. Consequently, EPAremoved these two projects from the economic analysis. A total of 18projects remain for the economic modeling of existing projects and 13remain for the economic modeling of new projects.    EPA added an environmental justice (EJ) analysis which investigatesthe potential for impacts on minorities and socioeconomicallydisadvantaged groups under the zero discharge option. EPA performed aTier 1 screening analysis, which combines geographic location and U.S.Census Bureau data to determine the number of persons living within 1mile and 50 miles of drilling waste handling and disposal sites, theirrace, and their socioeconomic status. A computer program developed byEPA Region 6 was used to rank and characterize sites on the basis ofwhether the populations near the site contain higher proportions ofminority and socioeconomically disadvantaged persons than the state asa whole. Based on scores derived for the 13 GOM onshore drilling wastehandling and disposal sites, EPA identified five facilities that couldbe potentially associated with disproportionate impacts on minoritiesor socioeconomically disadvantaged groups. EPA presents the results ofthe EJ analysis in Section IX.D. Water Quality Impact and Human Health Analyses    EPA received comments regarding the heavy metal leach factors usedin the water quality impact analyses but did not receive any specificdata that could be used in the analyses (Docket No. W-98-26, Record No.IV.A.a.2). EPA[[Page 6861]]therefore did not change these factors. However, EPA reevaluated themodeling used in the proposal that metals for which there were nofactors found in the literature were completely insoluble in thereceiving water (i.e., the leach factor would be zero). EPA estimatedthat these heavy metals would not be less soluble than iron which hasthe lowest leach percentage factor. Thus, the iron leach factor wastransferred to the following metals for which a zero leach factor waspreviously used: aluminum, antimony, beryllium, selenium, silver,thallium, tin, and titanium.E. Non-Water Quality Environmental Impact Analyses    As mentioned in Section III.E, EPA received additional informationregarding waste disposal practices in each of the three geographicareas (e.g., GOM, Offshore California, Cook Inlet, Alaska). As a resultof this information, EPA revised the modeling for the fraction of wasteeither injected at the drill site, injected on-shore or land disposed(see SBF Development Document). Though the percentage of waste injectedonsite versus hauled to shore (20% vs. 80%) in the GOM remainsunchanged, the method of onshore disposal has been revised for thefinal rule. In the GOM, 80% of the waste hauled to shore is injectedonshore and only 20% is landfarmed.    EPA estimates that all SBF wastes from Californian deep waterexploratory wells are sent onshore (i.e., 100% onshore disposal vs. 0%on-site injection). For all other wells (i.e., shallow waterdevelopment and exploratory and deep water development), EPA estimatesthat most of the offshore waste is disposed through offshore on-sitecuttings re-injection (i.e., 20% onshore disposal vs. 80% on-siteinjection) based on the fact that most of these wells are being drilledfrom fixed facilities. EPA estimates that most California offshorewastes sent onshore are disposed via onshore formation injection (i.e.,20% of offshore wastes sent onshore disposed via landfarming vs. 80% ofoffshore wastes sent onshore disposed via onshore injection) based onthe number of California land disposal operations.    At proposal, based on the record for the 1996 Coastal rule, EPAdetermined that onsite injection was not feasible throughout CookInlet, Alaska (see Coastal Development Document, EPA-821-R-96-023,Section 5.10.3). More recently, however, EPA identified in the April2000 NODA (65 FR 21558) that the SBF rule record now demonstrates thatmany Cook Inlet operators in Coastal waters are using cuttings re-injection (see Docket No. W-98-26: Record No. III.B.a.11, Record No.III.B.a.23, Record No. III.B.a.53). EPA contacted Cook Inlet operators(e.g., Phillips, Unocal, Marathon Oil) and the State regulatory agency,Alaska Oil and Gas Conservation Commission (AOGCC), for moreinformation on the most recent re-injection practices of Coastal andOffshore Cook Inlet operators (65 FR 21558). AOGCC regulations provideCook Inlet operators the opportunity to permit and operate Class IIdisposal wells and annular disposal activities. Information provided toEPA indicate that Cook Inlet operators in Coastal waters are availingthemselves of on-site cuttings injection and are receiving AOGCCpermits for this activity. Generally, Cook Inlet operators in Coastalwaters agree that on-site injection is available for most operations.    AOGCC also agreed that there should be enough formation re-injection disposal capacity for the small number of wells ( 5-10 wellsper year) being drilled in Cook Inlet Coastal waters. AOGCC stated,however, that case-specific limitations should be considered whenevaluating disposal options. For instance, Unocal has experienceddifficulty establishing formation injection in several wells that wereinitially considered for annular disposal. In addition, Cook Inletoperators have the burden of proving to AOGCC's satisfaction that thewaste will be confined to the formation disposal interval. Approval ofannular disposal includes a review of cementing and leak-off testrecords. In some instances the operator may also have to run a cementbond log. When an older well is converted for use as a disposal well,some of this information may not exist. In cases where there isinsufficient information, disposal is not allowed. Annular disposal isalso limited to the facility on which the waste is generated. AlthoughClass II disposal regulations don't restrict waste transport, it hasgenerally been the practice of the various fields' owners not to acceptany waste generated by other operators. In addition, AOGCC stated thata zero discharge requirement poses serious technical hurdles withrespect to the handling of drilling waste for exploration drilling withmobile rigs. Normally, there is neither capacity for storage or roomfor processing equipment on exploratory drilling rigs. Therefore, to beconservative for the NWQI analysis, EPA estimates that all of thecuttings from the Coastal Cook Inlet operations (i.e., shallow waterwells) are re-injected (i.e., 0% onshore disposal vs. 100% on-siteinjection) based on the ability of industry to dispose of oil-basedcuttings via on-site formation injection after gaining State regulatoryapproval.    In order to assess the SBF NWQIs relative to the total impacts fromdrilling operations, EPA included estimates of the daily drilling rigimpacts to the NWQIs from SBF-related activities. The additionalimpacts consist of fuel use and air emissions resulting from thevarious drilling rig pumps and motors as well as impacts of a dailyhelicopter trip for transporting personnel and/or supplies. Impactswere assessed for the number of days that an SBF interval is drilledversus the number of days well intervals are drilled using WBFs andOBFs and for the number of wells drilled using each of the drillingfluids.F. Numerical Limits for Retention of SBF Base Fluid on SBF-Cuttings    A series of potential numerical limits for retention of SBF basefluid on SBF-cuttings were developed based in part on combinations ofdata selection criteria suggested in comments on the April 2000 NODA.These data selection criteria include: (1) Existing record of retentioncalculations (i.e., ``back-up'' retort sheet information for qualityassurance/quality control purposes); and (2) foreign or domesticlocation of well drilling activity (e.g., North Sea, Canada). Numericallimits promulgated in today's final rule were based on data withexisting records of retention calculations, and they included data fromwell drilling activities in foreign countries. The inclusion of datafrom foreign countries is intended to include data representingdrilling with cuttings dryers at a wider range of geological formationsthan just the ones for which data was received from current operations.V. Development and Selection of Effluent Limitations Guidelines andStandardsA. Waste Generation and Characterization    Drill cuttings are produced continuously at the bottom of the holeat a rate dependent on a variety of factors including: (1) Theadvancement of the drill bit; (2) the size and design of drill bit used(e.g., polycrystalline diamond compact (PDC)); and (3) the drillingfluid type used. Drill cuttings are carried to the surface by thedrilling fluid, where the cuttings are separated from the drillingfluid by the solids control system. The drilling fluid is then[[Page 6862]]sent back to the active mud system (e.g., mud pumps, down hole, triptanks, etc.), provided it still has characteristics to meet technicalrequirements. Drilling fluids cool and lubricate the drill bit,stabilize the walls of the borehole, transport cuttings, and maintainequilibrium between the borehole and the formation pressures. Varioussizes of drill cuttings are separated by the solids separationsequipment, and it is necessary to remove the fines (i.e., small sizedcuttings or ``low gravity solids'') as well as the large cuttings fromthe drilling fluid to maintain the required rheological properties.    Increased recovery from the cuttings is more problematic for WBFthan for SBF because the WBF water-wets the cuttings which encouragesthe cuttings to disperse and spoil the drilling fluid properties.Therefore, compared to WBF, more aggressive methods of recovering SBFfrom the cuttings wastestream are practical.    SBFs, used or unused, are a valuable commodity and not a waste. Itis industry practice to continuously reuse the SBF while drilling awell interval, and at the end of the well, to ship the remaining SBFback to shore for refurbishment and reuse. One of the main incentivesfor operators to attempt to recover as much SBF as possible duringdrilling is the relatively high unit cost of SBF, approximately $160 to$300 per barrel, as compared to OBFs ($70 to 90 per barrel) and WBFs($45 per barrel) (Docket No. W-98-26, Record No. IV.B.a.13). Operatorsinvolved in the first 1998 GOM field demonstrations of cuttings dryers(i.e., advanced solids control technology) were attempting to obtainfurther reductions in drilling costs, beyond that obtained byshortening the overall drilling time for the well, by recovering moreSBF. SBFs are relatively easy to separate from the drill cuttingsbecause the drill cuttings do not disperse or hydrate in the drillingfluid to the same extent as compared to WBFs. Reducing cuttingshydration is particularly important in certain formations (e.g., shaleformations in GOM). With WBF, due to dispersion of the drill cuttings,drilling fluid components often need to be added to maintain therequired drilling fluid properties. These additions are often in excessof what the drilling system can accommodate. The excess ``dilutionvolume'' of WBF is a resultant waste. This dilution volume waste doesnot occur with SBF. For these reasons, SBF is only discharged as acontaminant of the drill cuttings wastestream. It is not discharged onpurpose as neat drilling fluid (i.e., drilling fluid not associatedwith cuttings).    Current practice is that the top well section is normally drilledwith a WBF. As the well becomes deeper, the performance requirements ofthe drilling fluid increase, and the operator may, at some point,decide that the drilling fluid system should be changed to either atraditional OBF, based on diesel oil or mineral oil, or an SBF. Thesystem, including the drill string and the solids separation equipment,must be changed entirely from the WBF to the SBF (or OBF) system, andthe two do not function as a blended system. The entire system iseither: (1) A water dispersible (aqueous) drilling fluid such as a WBF;or (2) an oleaginous drilling fluid such as OBFs, enhanced mineral oilbased drilling fluids, or SBFs. The decision to change the system froma WBF water dispersible system to an oleaginous drilling fluid dependson many factors including:    I. The operational considerations (e.g., rig type, risk of riserdisconnects, rig equipment, and distance from support facilities);    II. The relative drilling performance of one type fluid compared toanother (e.g., rate of penetration, well angle, hole size/casingprogram options, compatible drilling bit, and horizontal deviation);    III. The presence of geologic conditions that favor a particularfluid type or performance characteristic (e.g., formation stability/sensitivity, formation pore pressure vs. fracture gradient, andpotential for gas hydrate formation);    IV. Drilling fluid cost (i.e., base cost plus daily operatingcost);    V. drilling operation cost (i.e., rig cost plus logistic andoperation support); and    VI. Drilling waste disposal cost.    Industry has commented that while the right combination of factorsthat favor the use of SBF can occur in any area, they most frequentlyoccur with ``deep water'' operations (i.e., greater than or equal to1,000 feet of water). This is due to the fact that these operations arehigher cost and can therefore better justify the higher initial cost ofSBF use. Industry has also commented that SBF may be increasingly usedin shallow water wells due to the ability of SBF to increase averagerates of penetration and shorten average times to complete drillingoperations (Docket No. W-98-26, Record No. IV.A.a.3).    The volume of cuttings generated while drilling the SBF or OBFintervals of a well depends on the type of well (development orproduction) and the water depth (shallow or deep). EPA developed OBFand SBF model well characteristics from information provided by theAmerican Petroleum Institute (API). API provided well size date forfour types of wells currently drilling the GOM: development andexploratory wells in both deep water (i.e., greater than or equal to1,000 feet of water) and shallow water (i.e., less than 1,000 feet ofwater). These model wells are referred to as: (1) Shallow-waterdevelopment (SWD); (2) shallow-water exploratory (SWE); (3) deep-waterdevelopment (DWD); and (4) deep-water exploratory (DWE). For the fourmodel wells, EPA determined that the volumes of cuttings generated bythese SBF or OBF well intervals are (in barrels): 565 for SWD; 1,184for SWE; 855 for DWD; and 1,901 for DWE. These volumes represent onlythe rock, sand, and other formation solids drilled from the hole, anddo not include drilling fluid that adheres to these formation cuttings.These values also include the additional formation cuttings volume of7.5% washout. Washout is caving in or sloughing off of the well bore.Washout, therefore, increases hole volume and increases the amount ofcuttings generated when drilling a well. The washout percentage EPAused in its analyses (i.e., 7.5%) is based on the rule of thumbreported by industry representatives of 5 to 10% washout when drillingwith SBF or OBF.    Drilling fluid returning from the well is laden with drillcuttings. The drill cuttings range in size from large particles whichare on the order of a centimeter or more in size to small particles(i.e., fines or ``low gravity solids'') which are fractions of amillimeter in size. Standard or current practice solids control systemsemploy primary and secondary shale shakers in series with a ``finesremoval unit'' (e.g., decanting centrifuge or mud cleaner). Thedrilling fluid and drill cuttings from the well are first passedthrough primary shale shakers. These shakers remove the largestcuttings which are approximately 1 to 5 millimeters in size. Thedrilling fluid recovered from the primary shakers is then passed oversecondary shale shakers to remove smaller drill cuttings. Finally, aportion or all of the drilling fluid recovered from the primary andsecondary shakers may be passed through the fines removal unit toremove fines from the drilling fluid. It is important to remove finesfrom the drilling fluid in order to maintain the desired rheologicalproperties of the active drilling fluid system (e.g., viscosity,density). Thus, the cuttings wastestream normally consists ofdischarged cuttings from the primary and secondary shale shakers andfines from the fines removal unit.[[Page 6863]]    Operators using improved solids control technology process thecuttings discarded from the primary and secondary shale shakers througha ``cuttings dryer'' (e.g., vertical or horizontal centrifuge, squeezepress mud recovery unit, High-G linear shaker). The cuttings from thecuttings dryer are discharged and the recovered SBF is sent to thefines removal unit. The advantage of the cuttings dryer is that moreSBF is recovered for re-use and less SBF is discharged into the ocean.This, consequently, will reduce the pollutant loadings to the ocean andthe potential of the waste to cause anoxia (lack of oxygen) in thereceiving sediment.    As discussed in the April 2000 NODA (65 FR 21569), solids controlequipment generally breaks larger particles into smaller particles. Anundesirable increase in drilling fluid weight and viscosity can occurwhen drill solids degrade into fines and ultra-fines. Ultra-fines aregenerally classified as being less than 5 microns (10-6meters) in length and solids control equipment generally cannot removethese ultra-fines. An unacceptable high fines content (i.e., generally> 5% of total drilling fluid weight) may consequently lead to drillingproblems (e.g., undesirable rheological properties, stuck pipe).Therefore, it is possible that the increased recovery of SBF fromcuttings for re-use in the active mud system, often achieved throughuse of the cuttings dryer in solids control systems, may lead to abuild-up in fines for certain formation characteristics (e.g., highreactivity of formation cuttings, limited loss of drilling fluid intothe formation). In the April 2000 NODA, EPA solicited commentsregarding whether EPA's proposed numeric cuttings retention value mightcause operators (where there are unfavorable formation characteristics)to: (1) Dilute the fines in the active mud system through the additionof ``fresh'' SBF; and/or (2) capture a portion of the fines in acontainer and send the fines to shore for disposal.    Comments from API/NOIA identified only one instance in which theuse of a cuttings dryer in combination with a fines removal unit in theUnited States may have lead to an increase in ``fines build-up'' and aloss of circulation event (Docket No. W-98-26, Record No. IV.A.a.13).Further communication with additional industry stakeholders identifiedthat this well (Shell, Green Canyon 69, OCS-G-13159#3) was the firstapplication of the cuttings dryer type (horizontal centrifuge cuttingsdryer) in the GOM and inexperience with this type of technology mayhave contributed to the build-up of fines causing well problems.However, other commentors stated that fines build-up was not an issuefor the well in question (Docket No. W-98-26, Record No. IV.A.b.1).Moreover, further industry comments revealed that the properties offormations are often the main culprit of loss circulation and that thesame rig (Marianas) had a loss of circulation at another nearby well inthe same formation when a cuttings dryer was not being used (Docket No.W-98-26, Record No. IV.A.b.1). Therefore, based on the record, whichincludes over three dozen successful cuttings dryer deployments, EPAconcludes that fines build up is not an issue of concern when operatorsproperly operate and maintain cuttings dryers and fines removalequipment.    Drill cuttings are typically discharged continuously as they areseparated from the drilling fluid in the solids separation equipment.The drill cuttings will also carry a residual amount of adhereddrilling fluid. Therefore, the two parameters that make up the bulk ofthe pollutant loadings are TSS and what is measured by the API RetortMethod (Appendix 7) as Total Oil. TSS is comprised of two components:the drill cuttings themselves and the solids in the adhered drillingfluid. The drill cuttings are primarily small bits of stone, clay,shale, and sand. The source of the solids in the drilling fluid isprimarily the barite weighting agent, and clays (e.g., amine clays)which are added for filtration control and to modify the rheologicalproperties. Benthic smothering and/or sediment grain size alterationresulting in potential damage to invertebrate populations andalterations in benthic community structure is a concern withuncontrolled SBF drilling discharges due to the quantity andcharacteristics of associated TSS discharges. In general, largecuttings particles with a high percentage of adhering SBF (e.g., >12%(wt. SBF)/(wt. wet cuttings)) tend to conglomerate and quickly settleout to the benthic environment quickly near the well site.    Additionally, environmental impacts can be caused by toxic,conventional, and non-conventional pollutants adhering to the solids.The adhered SBF drilling fluid is mainly composed, on a volumetricbasis, of the synthetic material (i.e., ``base fluid''). Formation oilcan also contaminate SBF-cuttings and contribute priority,conventional, and non-conventional pollutants. The oleaginous material(i.e., SBF base fluid and formation oil) may be toxic and it maycontain priority pollutants such as polynuclear aromatic hydrocarbons(PAHs). Depending on bottom currents, temperature, and rate ofbiodegradation this oleaginous material may cause hypoxia (i.e.,reduction in dissolved oxygen concentrations) or anoxia (i.e., absenceof dissolved oxygen) in the immediate sediment. Oleaginous materialswhich biodegrade quickly will reduce dissolved oxygen concentrationsmore rapidly than more slowly degrading oleaginous materials. EPA,however, thinks that fast biodegradation is environmentally preferableto slower biodegradation despite the increased risk of temporaryhypoxia which accompanies fast biodegradation. EPA's position issupported by published seabed surveys which show that benthic re-colonization by infaunal individuals after the discharge of SBF-cuttings or OBF-cuttings can be correlated with the disappearance ofthe base fluid in the sediment. Large persistent cuttings piles mayprovide a source of environmental contamination for many years (DocketNo. W-98-26, Record No. IV.F.2). Moreover, benthic re-colonizationrates do not seem to be correlated with the severity of any hypoxic oranoxic effects that may result while the SBF base fluid is degrading ordispersing. Numerous studies show that SBF base fluids that biodegradefaster lead to a more rapid recovery of the pre-discharge benthiccommunity.    As a component of the drilling fluid, the barite weighting agent isalso discharged as a contaminant of the drill cuttings. Barite is amineral principally composed of barium sulfate (BaSO4), andit is known to generally have trace contaminants of several toxic heavymetals such as mercury, cadmium, arsenic, chromium, copper, lead,nickel, and zinc. SBF also contain non-conventional pollutants found inother drilling fluid components (e.g., emulsifiers, oil wetting agents,filtration control agents, and viscosifiers).    As previously stated in the April 2000 NODA (65 FR 21560), EPAlearned that SBF is controlled with zero discharge practices at thedrill floor, in the form of vacuums and sumps to retrieve spilledfluid. EPA also learned that approximately 75 barrels of fine solidsand barite, which have an approximate SBF content of 25%, canaccumulate in the dead spaces of the mud pit, sand trap, and otherequipment in the drilling fluid circulation system. Current practice isto either wash these solids out with water for overboard discharge, orto retain the waste solids for disposal. Several hundred barrels(approximately 200 to 400 barrels) of water are used to wash out themud pits. Industry representatives also indicated to EPA that those oiland gas extraction[[Page 6864]]operations that discharge wash water and accumulated solids firstrecover free SBF.B. Selection of Pollutant Parameters1. Stock Limitations and Standards for Base Fluids    a. General. In the final rule, where SBF-cuttings may bedischarged, except for Cook Inlet, Alaska, EPA is establishing BATlimitations and NSPS that require the synthetic materials which formthe base fluid of the SBFs to meet limitations and standards on PAHcontent, sediment toxicity, and biodegradation. If these stocklimitations are not met the technology basis for meeting theselimitations and standards is: (1) Product substitution; or (2) zerodischarge based on land disposal or cuttings re-injection. Theregulated toxic, conventional, and non-conventional pollutantparameters are identified below. A large range of synthetic,oleaginous, and water miscible materials are available for use as basefluids. These stock limitations on the base fluid are intended toencourage product substitution reflecting best available technology andbest available demonstrated technology wherein only those syntheticmaterials and other base fluids which minimize potential loadings andtoxicity may be discharged. Additionally, EPA is retaining BPT and BCTrequirements for SBFs and SBF-cuttings as no discharge of free oil asdetermined by the static sheen text (Appendix 1 of subpart A of 40 CFRPart 435).    As stated below in Section V.F, EPA is today promulgating BPT, BCT,BAT, and NSPS for SBFs and SBF-cuttings for Coastal Cook Inlet, Alaskaas zero discharge except when Coastal Cook Inlet, Alaska, operators areunable to dispose of their SBF-cuttings using any of the followingdisposal options: (1) On-site re-injection (annular disposal or ClassII UIC); (2) re-injection using a nearby Coastal or Offshore Class IIUIC disposal well; or (3) onshore disposal using a nearby Class II UICdisposal well or land application. If an operator is able to make theseshowings, then the operator would be subject to the same requirementsfor SBF-cuttings that apply elsewhere. The regulated toxic,conventional, and non-conventional pollutant parameters are identifiedbelow.    b. PAH Content. EPA is regulating the PAH content of base fluidsbecause PAHs are comprised of toxic priority pollutants. SBF basefluids typically do not contain PAHs, whereas the traditional OBF basefluids of diesel and mineral oil typically contain 5 to 10% PAH and0.35% PAH respectively. The PAHs typically found in diesel and mineraloil include: (1) the toxic priority pollutants fluorene, naphthalene,phenanthrene, and others; and (2) non-conventional pollutants such asalkylated benzenes and biphenyls. Therefore, the PAH BAT limitation andNSPS are components of this final regulation to help discriminatebetween acceptable and non-acceptable base fluids.    c. Sediment Toxicity. EPA is also regulating the sediment toxicityin base fluids as a non-conventional pollutant parameter and as anindicator for toxic pollutants and non-conventional pollutants in basefluids (e.g., enhanced mineral oils, internal olefins, linear alphaolefins, poly alpha olefins, paraffinic oils, C12-C14 vegetable esters of 2-hexanol and palm kernel oil, ``lowviscosity'' C8 esters, and other oleaginous materials). Ithas been shown, during EPA's development of the Offshore Guidelines,that establishing limits on toxicity encourages the use of less toxicdrilling fluids and additives. Many of the SBF base fluids have beenshown to have lower toxicity than OBF base fluids, but among SBFs someare more toxic than others. Today's final discharge option (i.e., BAT/NSPS Option 2) includes a base fluid sediment toxicity stocklimitation, as measured by the 10-day sediment toxicity test (ASTME1367-92) using a natural sediment or formulated sediment andLeptocheirus plumulosus as the test organism.    d. Biodegradation. EPA is also regulating the biodegradation inbase fluids as an indicator of the extent, in level and duration, ofthe toxic effect of toxic pollutants and non-conventional pollutantspresent in the base fluids (e.g., enhanced mineral oils, internalolefins, linear alpha olefins, poly alpha olefins, paraffinic oils,C12-C14 vegetable esters of 2-hexanol and palmkernel oil, ``low viscosity'' C8 esters, and otheroleaginous materials). Based on results from seabed surveys at siteswhere various base fluids have been discharged with drill cuttings, EPAbelieves that the results from the three biodegradation tests usedduring the rulemaking (i.e., solid phase test, anaerobic closed bottlebiodegradation test, respirometry biodegradation test) are indicativeof the relative rates of biodegradation in the marine environment. Inaddition, EPA thinks the biodegradation parameter correlates stronglywith the rate of recovery of the seabed where OBF- and SBF-cuttingshave been discharged. The various base fluids vary widely inbiodegradation rates, as measured by the three biodegradation methods.However, the relative ranking of the base fluids remain relativelysimilar across all three biodegradation tests.    As originally proposed in February 1999 (64 FR 5504) and re-statedin the April 2000 NODA (65 FR 21550), EPA is today promulgating a BATlimitation and NSPS to control the minimum amount of biodegradation ofbase fluid. Today's final discharge option (i.e., BAT/NSPS Option 2)includes a base fluid biodegradation stock limitation, as measured bythe marine anaerobic closed bottle biodegradation test (i.e., ISO11734).    e. Bioaccumulation. EPA also considered establishing a BATlimitation and NSPS that would limit the base fluid bioaccumulationpotential. The regulated parameters would be the non-conventional andtoxic priority pollutants that bioaccumulate. EPA reviewed the currentliterature to identify the bioaccumulation potential of various basefluids. EPA determined that SBFs are not expected to significantlybioaccumulate because of their extremely low water solubility andconsequent low bioavailability. Their propensity to biodegrade makesthem further unlikely to significantly bioaccumulate in marineorganisms.    EPA identified that hydrophobic chemicals (e.g., ester base fluids)that have a log Kow less than about 3 to 3.5 maybioaccumulate rapidly but not to high concentrations in tissues ofmarine organisms, particularly if they are readily biodegradable intonon-toxic metabolites (Docket No. W-98-26, Record No. IV.F.1). (Note:The octanol/water partition coefficient (Kow) is used as asurrogate for estimating lipid/water partitioning). Moreover,hydrophobic chemicals (e.g., C16-C18 internalolefins, various poly alpha olefins, and C18 n-paraffins)with a log Kow greater than about 6.5 to 7 do notbioaccumulate effectively from the water, because their solubility inboth the water and lipid phases is very low (Docket No. W-98-26, RecordNo. IV.F.1). Finally, the degradation by-products of SBF base fluids(e.g., alcohols) are likely to be more polar (i.e., more miscible withwater) than the parent substances. The higher water solubility willresult in these degradation by-products partitioning into the watercolumn and being diluted to toxicologically insignificantconcentrations.2. Discharge Limitations    a. Free Oil. Under BPT and BCT limitations for SBF-cuttings, EPAretains the prohibition on the discharge of free oil as determined bythe static sheen test[[Page 6865]](see Appendix 1 of subpart A of 40 CFR part 435). Under thisprohibition, drill cuttings may not be discharged when the associateddrilling fluid would fail the static sheen test. The prohibition on thedischarge of free oil is intended to minimize the formation of sheenson the surface of the receiving water. The regulated parameter of theno free oil limitation would be the conventional pollutant oil andgrease which separates from the SBF and causes a sheen on the surfaceof the receiving water.    The free oil discharge prohibition does not control the dischargeof oil and grease and crude oil contamination in SBFs as it would inWBFs. With WBFs, oils which may be present (e.g., diesel oil, mineraloil, formation oil, or other oleaginous materials) are present as thediscontinuous phase. As such these oils are free to rise to the surfaceof the receiving water where they may appear as a film or sheen upon ordiscoloration of the surface. By contrast, the oleaginous matrices ofSBFs do not disperse in water. In addition they are weighted withbarite, which causes them to sink as a mass without releasing eitherthe oleaginous materials which comprise the SBF or any contaminantformation oil. Thus, the test would not identify these pollutants.However, a portion of the SBF may rise to the surface to cause a sheen.The components that rise to the surface fall under the general categoryof oil and grease and are considered conventional pollutants.Therefore, the purpose of the no free oil limitation of today's finalregulation is to control the discharge of conventional pollutants whichseparate from the SBF and cause a sheen on the surface of the receivingwater. The limitation is not intended to control formation oilcontamination nor the total quantity of conventional pollutantsdischarged.    b. Formation Oil Contamination. As originally proposed in February1999 (64 FR 5505) and re-stated in the April 2000 NODA (65 FR 21552),EPA is today promulgating a BAT limitation and NSPS of zero dischargeto control formation oil contamination on SBF-cuttings. EPA is alsotoday promulgating a screening method (Reverse Phase Extraction (RPE)method presented in Appendix 6 to subpart A of part 435) and acompliance assurance method (Gas Chromatograph/Mass Spectrometer (GC/MS) method presented in Appendix 5 to subpart A of part 435).    Formation oil is an ``indicator'' pollutant for the many toxic andpriority pollutant pollutants present in formation (crude) oil (e.g.,aromatic and polynuclear aromatic hydrocarbons). These pollutantsinclude benzene, toluene, ethylbenzene, naphthalene, phenanthrene, andphenol. EPA is requiring that formation oil contamination be measuredat two points. First, EPA is requiring that operators verify anddocument that a SBF is free of formation oil contamination beforeinitial use of the SBF through use of the GC/MS compliance assurancemethod (Appendix 5 to subpart A of 40 CFR part 435). Second, EPA isrequiring that operators use the RPE method (Appendix 6 to subpart A of40 CFR part 435) for the SBF recovered by the solids control equipmentto detect formation oil contamination. The RPE method is a fluorescencetest and is appropriately ``weighted'' to better detect crude oils.These crude oils contain more toxic aromatic and PAH pollutants andshow brighter fluorescence (i.e., noncompliance) in the RPE method atlower levels of crude oil contamination. Since the RPE method is arelative brightness test, operators may also use the GC/MS complianceassurance method when the results from the RPE method are in doubt byeither the operator or the enforcement authority. Results from the GC/MS compliance assurance method will supersede those of the RPE method.    c. Retention of Drilling Fluid on Cuttings. EPA is todaypromulgating a BAT limitation and NSPS to control the retention ofdrilling fluid on drill cuttings. The BAT limitation and NSPS arepresented as the percentage of base fluid on wet cuttings (i.e., massbase fluid (g)/mass wet cuttings (g)), averaged over the entire wellsections drilled with SBF. The limitation and standard controls thequantity of drilling fluid discharged with the drill cuttings. Bothtoxic pollutants and non-conventional pollutants would be controlled bythis limitation. Several pollutants are present in the barite weightingagent, including the toxic metal pollutants arsenic, chromium, copper,lead, mercury, nickel, and zinc, and the non-conventional metalpollutants aluminum and tin. A complete SBF formulation also includesnon-conventional pollutants found in the SBF base fluids (e.g.,enhanced mineral oils, internal olefins, linear alpha olefins, polyalpha olefins, paraffinic oils, C12-C14 vegetableesters of 2-hexanol and palm kernel oil, ``low viscosity''C8 esters, and other oleaginous materials) and in otherdrilling fluid components (e.g., emulsifiers, oil wetting agents,filtration control agents, and viscosifiers). These pollutants wouldnot be controlled by the sediment toxicity stock limitations. Inresponse to the February 1999 proposal (64 FR 5501), EPA receivedcomments that these non-conventional pollutants include fatty acids(Docket No. W-98-26, Record No. III.A.a.7). EPA also received furtherinformation that the non-conventional pollutants in these drillingfluid components include amine clays, amine lignites, and dimer/trimerfatty acids (Docket No. W-98-26, Record No. III.B.b.1).    This limitation would also control the toxic effect of the drillingfluid and the persistence or biodegradation of the base fluid.Specifically, as stated in the April 2000 NODA (65 FR 21553), loweringthe percentage of residual drilling fluid retained on cuttingsincreases the recovery rate of the seabed receiving the cuttings(Docket No. W-98-26, Record No. I.D.b.30 and 31; Record No.III.B.a.15). Limiting the amount of SBF content in discharged cuttingscontrols: (1) The amount of toxic and non-conventional pollutants inSBF which are discharged to the ocean; (2) the biodegradation rate ofdischarged SBF; and (3) the potential for SBF-cuttings to developcuttings piles and mats which are deleterious to the benthicenvironment.    As originally proposed in February 1999 (64 FR 5547) and re-statedin the April 2000 NODA (65 FR 21552), EPA is today promulgating aretort and sampling compliance method for the cuttings retention BATlimitation and NSPS (see Appendix 7 to subpart A of 40 CFR part 435;API Recommended Practice 13B-2).    d. Sediment Toxicity. EPA is also regulating the sediment toxicityin SBF discharged with cuttings as a non-conventional pollutantparameter and as an indicator for toxic pollutants in SBFs. Asoriginally proposed in February 1999 (64 FR 5491) and re-stated inApril 2000 (65 FR 21557), EPA is today promulgating a BAT limitationand NSPS to control the maximum sediment toxicity of the SBF dischargedwith cuttings at the point of discharge. The sediment toxicity of theSBF-cuttings at the point of discharge is measured by the modifiedsediment toxicity test (ASTM E1367-92) using a natural sediment orformulated sediment and Leptocheirus plumulosus as the test organism.    EPA finds that the sediment toxicity test at the point of dischargeis practical as an indicator of the sediment toxicity of the drillingfluid at the point of discharge. The sediment toxicity test applied atthe point of discharge will control non-conventional pollutants foundin some drilling fluid components (e.g., emulsifiers, oil wettingagents, filtration control agents,[[Page 6866]]and viscosifiers) which are added to the base fluid in order to build acomplete SBF package. Other possible toxic pollutants in drillingfluids may include mercury, cadmium, arsenic, chromium, copper, lead,nickel, and zinc, and formation oil contaminants. As previously stated,establishing discharge limits on toxicity encourages the use of lesstoxic drilling fluids and additives. The modifications to the 10-daysediment toxicity test include shortening the test to 96-hours.Shortening the test will allow operators to continue drillingoperations while the sediment toxicity test is being conducted on thedischarged drilling fluid. Moreover, discriminatory power issubstantially reduced for the 10-day test on drilling fluid as comparedto the 96-hour test (i.e., the 10-day test is of lower practical use indetermining whether a SBF is substantially different from OBFs).Finally, operators discharging WBFs are already complying with abiological test at the point of discharge, the 96-hour SPP toxicitytest, which tests whole WBF aquatic toxicity using the test organismMysidopsis bahia.3. Maintenance of Current Requirements    Today's rule does not modify the existing BAT and NSPS limitationson the stock barite of 1 mg/kg mercury and 3 mg/kg cadmium. Theselimitations control the levels of toxic pollutant metals becausecleaner barite that meets the mercury and cadmium limits is also likelyto have reduced concentrations of other metals. Evaluation of therelationship between cadmium and mercury and the trace metals in bariteshows a correlation between the concentration of mercury with theconcentration of arsenic, chromium, copper, lead, molybdenum, sodium,tin, titanium and zinc (see Section VI, Offshore Development Document,EPA-821-R-93-003).    Today's rule does not modify the existing BAT and NSPS limitationsprohibiting the discharge of drilling wastes containing diesel oil inany amount. Diesel oil is considered an ``indicator'' for the controlof specific toxic pollutants. These pollutants include benzene,toluene, ethylbenzene, naphthalene, phenanthrene, and phenol. Dieseloil may contain from 3 to 10% by volume PAHs, which constitute the moretoxic pollutants in petroleum products.    Today's rule does not modify the existing BAT limitation and NSPSfor controlling the maximum aqueous phase toxicity of SBF-cuttings atpoint of discharge using the suspended particulate phase (SPP) test(see Appendix 2 of subpart A of Part 435). The BAT limitation and NSPSfor controlling aqueous toxicity of discharged SBF-cuttings is retainedas the minimum 96-hour LC50 of the SPP shall be 3% byvolume. EPA is interested in controlling the toxicity of drillingfluids in the sediment and the water column and is requiring both asediment toxicity test and an aqueous phase toxicity test to assessoverall toxicity of the drilling fluid at the point of discharge. EPAfinds that the SPP test at the point of discharge is practical as ameasurement of the aquatic toxicity of the drilling fluid at the pointof discharge. The discharge SPP test will control non-conventionalpollutants found in drilling fluid components (e.g., emulsifiers, oilwetting agents, filtration control agents, and viscosifiers) which areadded to the base fluid in order to build a complete SBF package.Moreover, operators discharging WBFs are already complying with the SPPtoxicity test on discharged WBFs.C. Regulatory Options Considered and Selected for Drilling Fluid NotAssociated With Drill Cuttings    In the February 1999 proposal, EPA proposed BPT, BCT, BAT, and NSPSas zero discharge for SBFs not associated with drill cuttings. In theApril 2000 NODA, EPA published two options for the final rule for theBAT limitation and NSPS for controlling SBFs not associated with SBFdrill cuttings: (1) Zero discharge; or (2) allowing operators to chooseeither zero discharge or an alternative set of BMPs with anaccompanying compliance method. Industry supported the second optionstating that the first option (zero discharge) would result in thecostly and potentially dangerous collection, shipping, and disposal oflarge quantities of rig site wash water containing only a smallquantity of SBF (Docket No. W-98-26, Record No. IV.A.a.13). Industryalso stated that BMPs would be extremely effective at reducing thequantity of non-cuttings related SBF and would focus operators'attention on reducing these discharges.    EPA is today promulgating BPT, BCT, BAT, and NSPS of zero dischargefor SBFs not associated with drill cuttings. This wastestream consistsof neat SBFs that are intended for use in the downhole drillingoperations (e.g., drill bit lubrication and cooling, hole stability).This wastestream is transferred from supply boats to the drilling rigand can be released during these transfer operations. This wastestreamis often spilled on the drill deck but contained through gratedtroughs, vacuums, or squeegee systems. This wastestream is also held innumerous tanks during all phases of the drilling operation (e.g., triptanks, storage tanks). EPA received information that rare occurrencesof improper SBF transfer procedures (e.g., no bunkering procedures inplace for rig loading manifolds) and improper operation of active mudsystem equipment (e.g., no lock-out, tag-out procedures in place formud pit dump valves) has the potential for the discharge of tens tohundreds of barrels of neat SBF, or SBF not associated with cuttings,if containment is not practiced (Docket No. W-98-26, Record No.IV.A.a.26, QTECH LTD Reports for Ocean America and Discoverer 534).    Current practice for control of SBF not associated with drillcuttings is zero discharge (e.g., drill deck containment, bunkeringprocedures), primarily due to the value of SBFs recovered and reused.Therefore, zero discharge for SBF not associated with drill cuttings istechnologically available and economically achievable. Moreover, thesecontrols generally allow the re-use of SBF in the drilling operationand has no unacceptable NWQIs.    EPA has also decided that solids accumulated at the end of the well(``accumulated solids'') and wash water used to clean out accumulatedsolids or on the drill floor are associated with drill cuttings and aretherefore not controlled by the zero discharge requirement for SBFs notassociated with drill cuttings (see Section V.F.2.b).D. BPT Technology Options Considered and Selected for Drilling FluidAssociated With Drill Cuttings    EPA is today promulgating BPT effluent limitations for the cuttingscontaminated with SBFs (``SBF-cuttings''). The BPT effluent limitationspromulgated today for SBF-cuttings would control free oil as aconventional pollutant. The BPT limitation is no free oil as measuredby the static sheen test, performed on SBF separated from the cuttingsin U.S. Offshore waters and Coastal Cook Inlet, Alaska.    In setting the no free oil limitation in U.S. Offshore waters andCoastal Cook Inlet, Alaska, EPA considered the sheen characteristics ofcurrently available SBFs. Since this requirement is currently met bydischargers in the GOM, EPA anticipates no additional costs to theindustry to comply with this limitation. Therefore, EPA believes thatthis limitation represents the appropriate level of control for SBFsassociated with drill cuttings.[[Page 6867]]E. BCT Technology Options Considered and Selected for Drilling FluidAssociated With Drill Cuttings    In July 1986, EPA promulgated a methodology for establishing BCTeffluent limitations. EPA evaluates the reasonableness of BCT candidatetechnologies--those that are technologically feasible--by applying atwo part cost test: (1) A POTW test; and (2) an industry cost-effectiveness test.    EPA first calculates the cost per pound of conventional pollutantremoved by industrial dischargers in upgrading from BPT to a BCTcandidate technology and then compares this cost to the cost per poundof conventional pollutants removed in upgrading POTWs from secondarytreatment. The upgrade cost to industry must be less than the POTWbenchmark of $0.25 per pound (in 1976 dollars). In the industry cost-effectiveness test, the ratio of the incremental BPT to BCT costdivided by the BPT cost for the industry must be less than 1.29 (i.e.,the cost increase must be less than 29%).    The BCT effluent limitations promulgated today would control freeoil as a conventional pollutant. EPA is today promulgating a BCTeffluent limitation for SBF-cuttings of no free oil equivalent to theBPT limitation for SBF-cuttings of no free oil as determined by thestatic sheen test in U.S. Offshore waters and Coastal Cook Inlet,Alaska.    In developing BCT limits for the U.S. Offshore waters and CoastalCook Inlet, Alaska, EPA considered whether there are technologies(including drilling fluid formulations) that achieve greater removalsof conventional pollutants than promulgated for BPT, and whether thosetechnologies are cost-reasonable according to the BCT Cost Test. EPAidentified no technologies that can achieve greater removals ofconventional pollutants as compared with the U.S. Offshore waters andCoastal Cook Inlet BPT requirements that are also cost-reasonable underthe BCT Cost Test. Accordingly EPA is today promulgating BCT effluentlimitations for SBF-cuttings equal to the promulgated BPT effluentlimitations for SBF-cuttings in U.S. Offshore waters and Coastal CookInlet, Alaska.F. BAT Technology Options Considered and Selected for Drilling FluidAssociated With Drill Cuttings    EPA is promulgating stock limitations and discharge limitations ina two part approach to control SBF-cuttings discharges under BAT. Thefirst part is based on product substitution through use of stocklimitations (e.g., sediment toxicity, biodegradation, PAH content,metals content) and discharge limitations (e.g., diesel oilprohibition, formation oil prohibition, sediment toxicity, aqueoustoxicity). The second part is the control of the quantity of SBFdischarged with SBF-cuttings. As previously stated in the April 2000NODA, EPA finds that the second part is particularly important becauselimiting the amount of SBF content in discharged cuttings controls: (1)The amount of SBF discharged to the ocean; (2) the biodegradation rateof discharged SBF; and (3) the potential for SBF-cuttings to developcuttings piles and mats which are detrimental to the benthicenvironment.    EPA is also today retaining the existing BAT limitations on: (1)The stock barite of 1 mg/kg mercury and 3 mg/kg cadmium; (2) themaximum aqueous toxicity of discharged SBF-cuttings as the minimum 96-hour LC50 of the Suspended Particulate Phase toxicity test(SPP) shall be 3% by volume; and (3) prohibiting the discharge ofdrilling wastes containing diesel oil in any amount. These limitationscontrol the levels of toxic metal and aromatic pollutants respectively.EPA at this time thinks that all of these components are essential forappropriate control of SBF-cuttings discharges.    The BAT effluent limitations promulgated today for SBF-cuttingswould control a variety of toxic and non-conventional pollutants in thestock base fluids by controlling their PAH content, sediment toxicity,and biodegradation. The BAT effluent limitations promulgated today forSBF-cuttings would also control a variety of toxic and non-conventionalpollutants at the point of discharge by controlling formation oilcontamination, sediment toxicity, and the quantity of SBF discharged.The BAT stock and discharge limitations are described below.    The BAT level of control in the U.S. Offshore waters has beendeveloped taking into consideration among other things: (1) Theavailability, cost, and environmental performance of SBF base fluids interms of PAH content, sediment toxicity, and biodegradation rate; (2)the availability, cost, and environmental performance of SBFs retainedon the cuttings discharge in terms of sediment toxicity andbiodegradation rate; (3) the frequency of formation oil contaminationat the various control levels for the discharges; (4) the availability,cost, and environmental performance of equipment and methods to recoverSBF from the drill cuttings being discharged; and (5) the NWQIs of eachoption. By environmental performance, EPA means both a reduction in thequantity of pollutants discharged to the ocean and a reduction in theirenvironmental effects in terms of sediment toxicity, aquatic toxicity,and biodegradation rate. Issues related to the technical availabilityand economic achievability of today's promulgated BAT limitations arediscussed below by regulated parameter. The NWQIs of each selectedoption is discussed in Section VIII below. EPA also considered NWQIs inselecting the controlled discharge option for SBF-cuttings (i.e., BAT/NSPS Option 2) (see Section VIII).    EPA and industry sediment toxicity and biodegradation laboratorystudies show that both vegetable esters and low viscosity esters havebetter environmental performance than all other SBF base fluids. EPA,however, rejected the option of basing BAT sediment toxicity andbiodegradation stock limitations and NSPS solely on vegetable estersand low viscosity esters because the record does not indicate thatthese fluids can be used in drilling situations throughout the offshoresubcategory nor could EPA predict the conditions and circumstanceswhere these fluids would be able to be used (see Section V.F.1.a). EPAis sufficiently satisfied, however, that both esters provide betterenvironmental performance (e.g., sediment toxicity, biodegradation).Consequently, EPA is promulgating an alternative higher retention oncuttings (ROC) BAT discharge limitation to encourage the use of esters.The higher ROC discharge limitation for SBFs complying with the stocklimitations based on esters is derived from data representing fourcuttings dryer technologies (e.g., vertical centrifuge, horizontalcentrifuge, squeeze press mud recovery unit, and High-G linear shaker).The lower ROC BAT discharge limitation for the SBFs complying with theC16-C18 internal olefin stock limitations isbased on data from the two top performing cuttings dryer technologies(e.g., vertical centrifuge and horizontal centrifuge). EPA datademonstrates that operators properly using these cuttings dryertechnologies (e.g., vertical centrifuge, horizontal centrifuge, squeezepress, High-G linear shaker) will be able to comply with the finalhigher ROC numerical limitation for ester-based SBFs. EPA believes thatthis balancing of the importance of retention values with environmentalperformance as reflected by sediment toxicity and biodegradation ratesis justified because of the greater ability of esters to[[Page 6868]]biodegrade and of their lower sediment toxicity.    Therefore, EPA balanced the environmental performance of the basefluid (in terms of sediment toxicity and biodegradation) with theenvironmental performance of cuttings associated with drilling fluids(in terms of the retention on cuttings limit) to determine theappropriate best available technology. EPA determined that the improvedtoxicity and biodegradation of the ester based fluids justifiedincreased flexibility in the ROC limitation as long as the limitationreflected the use of cuttings dryers technologies.    EPA, however, did not base the higher ROC BAT discharge limitationfor esters on current shale shaker technology because this does notrepresent the best available technology (or best available demonstratedtechnology). EPA does not believe that the improved environmentalperformance of esters justifies the huge difference in pollutantloadings between existing shale shaker technology and newer cuttingsdryer technology. Because the effluent limitations and standardspromulgated in this rule account for variability, the effluentlimitation and standards are higher than the long term average uponwhich the technology is based. Here, the LTA for the esters ROClimitation of 9.4% is 4.8%; while the LTA for the IOs ROC limitation of6.9% is 3.82%. By contrast, the LTA for existing shale shakertechnology is 10.2%. This difference translates to 118 million poundsper year of pollutants being discharged using the existing and newmodel well counts for the selected BAT option (i.e., BAT/NSPS Option 2)(see SBF Development Document). Further, as previously stated in theApril 2000 NODA (65 FR 21553), field results show that: (1) Cuttingsare dispersed during transit to the seabed and no cuttings piles areformed when SBF concentrations on cuttings are held below 5%; and (2)cuttings discharged from cuttings dryers (with SBF retention valuesunder 5%) in combination with a sea water flush, hydrate very quicklyand disperse like water-based cuttings. Thus, while EPA is willing toprovide additional flexibility to dischargers of ester-based fluids,EPA believes that the appropriate technology basis that reflects BAT iscuttings dryers technology.    EPA determined that zero discharge for BAT was technically feasibleand economically achievable because prior to the use of SBFs, theindustry was able to operate using only the traditional OBFs (based ondiesel oil and mineral oil), which are prohibited from discharge. EPAconcluded that a zero discharge BAT limitation for SBF-cuttings woulddecrease the use of SBFs in favor of OBFs and WBFs. This is because azero discharge BAT limitation for SBF-cuttings would create anincentive for operators to use the least expensive drilling fluids(i.e., OBFs, WBFs) in order to minimize overall compliance costs.    EPA rejected the BAT zero discharge option for SBF-cuttings wastesbecause it would result in unacceptable increases in NWQIs. Therefore,EPA rejected the zero discharge option for SBF-cuttings wastes in U.S.waters in the Offshore subcategory of 40 CFR part 435 (``U.S. Offshorewaters''). As previously stated in Section II.B, use of OBFs in placeof SBFs would lead to an increase in NWQIs including the toxicity ofthe drilling waste. Use of WBFs in place of SBFs would generally leadto a per well increase in pollutants discharged, an increase in NWQIs,and an increase in aquatic toxicity. WBF drilling operations lead toper well increases in pollutants discharged because WBFs generate sixtimes more washout (e.g., sloughing) of the well wall than SBFs. Also,WBF drilling operations lead to increases in NWQIs because WBF drillingoperations generally take longer than SBF drilling operations whichlead to more air emissions and fuel usage from drilling rigs andequipment. Aquatic toxicity generally increases when drilling fluidmanufacturers add supplements (e.g., glycols, shale inhibitors) to WBFsfor the purpose of making WBFs have technical capabilities (e.g.,lubricity, shale suppression) similar to SBFs. EPA estimates that,under the zero discharge option, some operators would switch to WBFcompositions with more non aqueous drilling fluid properties (e.g.,lubricity, shale suppression), and that these WBFs would exhibitgreater aquatic toxicity.    EPA's analyses show that under the SBF-cuttings zero dischargeoption as compared to current practice, for U.S. Offshore watersexisting sources, there would be an increase of 35 million pounds ofcuttings annually shipped to shore for disposal in non-hazardousoilfield waste (NOW) sites and an increase of 166 million pounds ofcuttings annually injected. In addition, under the SBF-cuttings zerodischarge option, operators would use the more toxic OBFs. The zerodischarge option for SBF-cuttings would lead to an increase in annualfuel usage of 358,664 BOE and an increase in annual air emissions of5,602 tons. Finally, the SBF-cuttings zero discharge option in the U.S.Offshore waters would lead to an increase of 51 million pounds of WBFcuttings being discharged to U.S. Offshore waters. This pollutantloading increase is a result of GOM operators switching from efficientSBF drilling to less efficient WBF drilling.    EPA's analysis shows that the impacts of adequately controlled SBFdischarges to the water column and benthic environment are of limitedscope and duration. By contrast, the landfilling of OBF-cuttings is ofa longer term duration and associated pollutants may affect ambientair, soil, and groundwater quality. EPA and DOE documented at leastfive CERCLA (or ``Superfund'') sites in Louisiana and Californiacontaminated with oilfield wastes and more than a dozen other sitessubject to Federal or State cleanup actions.    Nonetheless, while SBF-cuttings discharge with adequate controls ispreferred over zero discharge in U.S. Offshore waters, SBF-cuttingsdischarge with inadequate controls is not preferred over zerodischarge. EPA believes that to allow discharge of SBF-cuttings in U.S.Offshore waters, there must be appropriate controls to ensure thatEPA's discharge limitations reflect the ``best available technology''or other appropriate level of technology. EPA has worked with industryto address the appropriate determination of PAH content, sedimenttoxicity, biodegradation, quantity of SBF discharged, and formation oilcontamination that are technically available, economically achievable,and have acceptable NWQIs. The final BAT limitations are a result ofthis effort and are discussed below.    EPA is today promulgating BAT of zero discharge for SBF-cuttingsfor Coastal Cook Inlet, Alaska except when Coastal Cook Inlet, Alaska,operators are unable to dispose of their SBF-cuttings using any of thefollowing disposal options: (1) On-site re-injection (annular disposalor Class II UIC); (2) re-injection using a nearby Coastal or OffshoreClass II UIC disposal well; or (3) onshore disposal using a nearbyClass II UIC disposal well or land application. Coastal Cook Inlet,Alaska, operators are required to demonstrate to the NPDES permitcontrolling authority that none of the above three disposal options aretechnically feasible in order to qualify for the alternate BATlimitation. Coastal Cook Inlet, Alaska, operators that qualify for thealternate BAT limitation are allowed to discharge SBF-cuttings at thesame level of BAT control as operators in Offshore waters. The NPDESpermit controlling authority will use the procedure given in Appendix 1to subpart D of 40 CFR part 435 to establish whether or not a CoastalCook Inlet, Alaska, operator qualifies for the[[Page 6869]]SBF-cuttings zero discharge exemption. As stated in Appendix 1 tosubpart D of 40 CFR part 435, the following factors are considered inthe determination of whether or not Coastal Cook Inlet, Alaska,operators qualify for the SBF-cuttings zero discharge exemption: (1)Inability to establish formation injection in wells that were initiallyconsidered for annular or dedicated disposal; (2) inability to prove toUIC controlling authority that the waste will be confined to theformation disposal interval; (3) inability to transport drilling wasteto an offshore Class II UIC disposal well or an onshore disposal site;and (4) whether or not there is no available land disposal facilities(e.g., onshore re-injection, land disposal).    EPA finds that this option is technically available andeconomically achievable. Operators are currently barred fromdischarging OBFs, SBFs, and enhanced mineral oil based drilling fluidsunder the Cook Inlet NPDES general permit (64 FR 11889). As previouslydiscussed in Section IV.E, EPA identified that many Cook Inletoperators in Coastal waters are using cuttings re-injection to complywith zero discharge disposal requirements for OBFs and OBF-cuttings.EPA contacted Cook Inlet operators (e.g., Phillips, Unocal, MarathonOil) and the State regulatory agency, AOGCC, for more information onthe most recent re-injection practices of Coastal and Offshore CookInlet operators. AOGCC stated that there should be enough formation re-injection disposal capacity for the small number of non-aqueousdrilling fluid wells (5-10 wells per year) being drilled in Cook InletCoastal waters. Therefore, since Coastal Cook Inlet operators arealready complying with zero discharge of OBF- and SBF-cuttings, thisoption is economically achievable as there are no incrementalcompliance costs.    AOGCC stated, however, that case specific limitations should beconsidered when evaluating disposal options (see Section IV.E). CookInlet, Alaska, operators may experience the following difficulties inattempting to comply with a zero discharge requirement for SBFs: (1)Inability to establish formation injection in wells that were initiallyconsidered for annular or dedicated Class II UIC disposal; (2)inability to prove to AOGCC's satisfaction that the waste will beconfined to the formation disposal interval; and (3) inability totransport drilling waste to an offshore Class II UIC disposal well oran onshore disposal site. EPA believes that while these problems arecurrently not presented by drilling in Cook Inlet, they could be aproblem in the future. Further, EPA believes this to be a greaterproblem in Cook Inlet where climate, tides, and its distance fromcommercial disposal sites make transportation to shore less feasiblethan in other offshore waters near the continental U.S. If EPA did notprovide for some exceptions within the guideline itself, and theseproblems presented themselves beyond the time frame for requesting aFundamentally Different Factors variance (under section 301(n)(2) ofthe CWA, 180 days) this would render zero discharge not achievable.Therefore, EPA believes it is reasonable to provide for someflexibility to the current practice of zero discharge in Cook Inlet.    EPA further finds the NWQIs of this option for Cook Inlet to beacceptable. As previously stated, few non-aqueous drilling fluid wellsare drilled in Coastal Cook Inlet, Alaska (5-10 wells per year). EPAfinds that the small number of wells drilled per year (even if all ofthem are drilled using SBF) leads to very small increases in NWQIs.Tables 6 though 10 describe the annual air emissions and fuel usage forthe three geographic regions including Cook Inlet, Alaska. Inparticular, a zero discharge requirement for SBFs and SBF-cuttings inCook Inlet, Alaska, would lead to an annual increase of 94 tons of airemissions and 6,067 BOE fuel used for existing sources. EPA does notanticipate and new sources in Cook Inlet, Alaska. Consequently, EPAfinds that the overall small increases in NWQIs from the zero dischargeoption, as compared to either of the two SBF-cuttings dischargeoptions, in Coastal Cook Inlet, Alaska, are acceptable. The two SBF-cuttings discharge options show little change in NWQIs as compared tobaseline (see Tables 6 though 9).1. Stock Base Fluid Technical Availability and Economic Achievability    a. Introduction. As SBFs have developed over the past few years,the industry has come to use mainly a limited number of primary basefluids. These include the internal olefins, linear alpha olefins, polyalpha olefins, paraffinic oils, C12-C14 vegetableesters of 2-hexanol and palm kernel oil, and ``low viscosity''C8 esters. These fluids represent virtually all the SBFscurrently used in oil and gas extraction industry. EPA collected dataon performance, environmental impact, and costs for these SBFs todevelop the effluent limitations for today's final rule. The followingdefinitions are used in this preamble to describe various SBFs: (1)Internal olefin (IO) refers to a series of isomeric forms ofC16 and C18 alkenes; (2) linear alpha olefin(LAO) refers to a series of isomeric forms of C14 andC16 monoenes; (3) poly alpha olefin (PAO) refers to a mixmainly comprised of a hydrogenated decene dimerC20H62 (95%), with lesser amounts ofC30H62 (4.8%) and C10H22(0.2%); (4) vegetable ester refers to a monoester of 2-ethylhexanol andsaturated fatty acids with chain lengths in the range C8-C16; and (5) ``low viscosity'' ester refers to an ester ofnatural or synthetic C8 fatty acids and alcohols. EPA alsohas data on other SBF base fluids, such as enhanced mineral oil,paraffinic oils (i.e., saturated hydrocarbons or ``alkanes''), and thetraditional OBF base fluids: mineral oil and diesel oil.    The stock base fluid limitations in today's rule are based on thetechnology of product substitution. The promulgated limitations aretechnically available because they are based on currently availablebase fluids that can be used in the wide variety of drilling situationsin U.S. offshore waters. EPA anticipates that the base fluids meetingall requirements would include vegetable esters, low viscosity esters,and internal olefins. In addition, based on current information, EPAbelieves that the stock base fluid controls on PAH content, sedimenttoxicity, and biodegradation rate being promulgated today aresufficient to only allow the discharge of only those base fluids (e.g.,esters, internal olefins) with lower bioaccumulation potentials (i.e.,log Kow 3 to 3.5 and log Kow> 6.5 to 7).Therefore, EPA found it was unnecessary to promulgate a separatelimitation for bioaccumulation.    As previously stated in April 2000 (65 FR 21554), EPA consideredbasing the sediment toxicity and biodegradation stock limitations andstandards solely on vegetable esters (i.e., original esters) instead ofthe proposed C16-C18 IO. EPA also consideredsubcategorizing the final rule to determine when vegetable esters arenot practical and when C16-C18 IOs could be usedinstead. EPA considered these options due to the potential for betterenvironmental performance of vegetable ester-based drilling fluids. EPAand industry analytical testing show that esters have better sedimenttoxicity and biodegradation performance.    EPA rejected the option of basing sediment toxicity andbiodegradation stock limitations and standards on vegetable esters dueto several technical limitations. These technical limitations ofvegetable esters preclude their use in all areas of the GOM, OffshoreCalifornia, and Cook Inlet, Alaska. Vegetable ester technicallimitations[[Page 6870]]include: (1) High viscosity compared with other IO SBFs at alltemperatures, with an increasing difference as temperature decreases,leading to lower rates of penetration in wells and greater probabilityof losses due to higher equivalent circulating densities; (2) high gelstrength in risers that develops when a vegetable ester-based SBF isnot circulated; (3) a high temperature stability limit ranging fromabout 225  deg.F to perhaps 320  deg.F--the exact value depends on thedetailed chemistry of the vegetable ester (i.e., the acid, the alcohol)and the drilling fluid chemistry; (4) reduction of the thermalstability limit through hydrolysis when vegetable esters are in contactwith highly basic materials (e.g., lime, green cement) at elevatedtemperatures; and (5) less tolerance of the muds to contamination byseawater, cement, and drill solids than is observed for IO-SBFs (DocketNo. W-98-26: Record No. IV.A.a.3, Attachment A2--``Limitations ofEsters'; Record No. IV.A.a.13, Attachments Ester-51, 52, 53, 54, 56).    EPA also rejected the option of subcategorizing the use of estersto define drilling conditions when only esters could be allowed for acontrolled discharge. EPA could not establish a ``bright line''rationale to define the situation where only esters should be thebenchmark fluid (i.e., only esters would be allowed for a controlleddischarge). EPA considered many of the engineering factors used forselection of a drilling fluid (e.g., rig size and equipment; formationcharacteristics; water depth and environment; lubricity, rheological,and thixotropic requirements) and determined that this type of sub-categorization was not possible. EPA, however, is encouraging the useof esters by promulgating a higher ROC limitation and standard whenesters are used.    EPA also considered basing sediment toxicity and biodegradationstock limitations and standards on low viscosity esters. Comments tothe April 2000 NODA state that laboratory analyses, which were designedto simulate GOM conditions to which a fluid may be exposed, indicatethat low viscosity esters have the following technical properties: (1)Similar or better viscosity than C16-C18 IOs; (2)can be used to formulate stable low viscosity ester-based SBFs up to300  deg.F; (3) can be used to formulate low viscosity ester-based SBFsto 16.0+ lbs/gal mud weight; (4) can reduce oil/water ratios to 70/30,thus reducing volumes of base fluid discharged; (5) high tolerance todrilled solids; (6) flat gels make it easier to break circulation,minimizing initial circulation pressures and subsequent risk offracture; (7) high tolerance to seawater contamination; and (8)rheological properties can be adjusted by use of additives to suitspecific conditions (Docket No. W-98-26, Record No. IV.A.a.7). EPA alsoreceived information on one well section drilled with low viscosityesters. Some of the results from this low viscosity ester well sectionwere compared to the results from another well section in the samelocation where C16-C18 IOs were used. Theseresults show that the low viscosity ester had: (1) Comparable or betterequivalent circulating densities (i.e., acceptable fluid properties);and (2) faster ROP through better hole cleaning and higher lubricity(i.e., fewer days required to drill to total depth which lead to lessNWQI and overall drilling costs). The low viscosity esters arerelatively new base fluids and have only recently been available to themarket. Despite the results from the laboratory analyses and one wellsection, EPA does not believe that this is enough information to makethe determination that low viscosity esters can be used in all ornearly all drilling conditions in the offshore U.S. waters (e.g.,differing formations, water depths, and temperatures). Therefore, EPArejected the option of basing sediment toxicity and biodegradationstock limitations and standards on low viscosity esters. EPA issufficiently satisfied, however, that low viscosity esters andvegetable esters provide better environmental performance (e.g.,sediment toxicity, biodegradation). Consequently, EPA is promulgatinghigher retention on cuttings discharge limitations where esters areused to encourage operators to use esters when possible.    b. PAH Content Technical Availability. Today's promulgatedlimitation of PAH content for U.S. Offshore waters is a weight ratiodefined as the weight of PAH (as phenanthrene) per weight of the stockbase fluid sample. The PAH weight ratio is 0.001%, or 10 parts permillion (ppm). This limitation is based on the availability of basefluids that are free of PAHs and the detection of the PAHs by EPAMethod 1654A, ``PAH Content of Oil by High Performance LiquidChromatography with a UV Detector.'' Method 1654A was published inMethods for the Determination of Diesel, Mineral and Crude Oils inOffshore Oil and Gas Industry Discharges (EPA-821-R-92-008,incorporated by reference and available from National TechnicalInformation Service at (703) 605-6000). As originally proposed inFebruary 1999 (64 FR 5503), EPA is promulgating the use of the EPAMethod 1654A for compliance with this PAH content BAT limitation.    EPA's promulgated PAH content limitation is technically available.Producers of several SBF base fluids have reported to EPA that theirbase fluids are free of PAHs. The base fluids which suppliers havereported are free of PAHs include IOs, LAOs, vegetable esters, lowviscosity esters, certain enhanced mineral oils, synthetic paraffins,certain non-synthetic paraffins, and others. The use of these fluidscan accommodate the broad varieties of drilling situations faced byindustry in offshore U.S. waters (see SBF Development Document, ChapterIV). Compliance with the stock BAT limitation and NSPS on PAH contentwill be achieved by product substitution.    c. Sediment Toxicity Technical Availability. EPA is todaypromulgating a sediment toxicity stock base fluid limitation that wouldonly allow the discharge of SBF-cuttings using SBF base fluids as toxicor less toxic, but not more toxic, than C16-C18IOs. Alternatively, this limitation could be expressed in terms of a``sediment toxicity ratio'' which is defined as 10-day LC50of C16-C18 internal olefins divided by the 10-dayLC50 of stock base fluid being tested. EPA is promulgating asediment toxicity ratio of less than 1.0. Compliance with thislimitation is determined by the 10-day Leptocheirus plumulosus sedimenttoxicity test (i.e., ASTM E1367-92: ``Standard Guide for Conducting 10-day Static Sediment Toxicity Tests With Marine and Estuarine Amphipods'(incorporated by reference and available from ASTM, 100 Bar HarborDrive, West Conshohocken, PA 19428), supplemented with the preparationprocedure specified in Appendix 3 of Subpart A of 40 CFR part 435). Asoriginally proposed in February 1999 (64 FR 5503) and re-stated inApril 2000 (65 FR 21549), EPA is promulgating the use of the ASTME1367-92 method for compliance with this sediment toxicity BATlimitation.    Since the February 1999 proposal, EPA and other researchersconducted numerous 10-day L. plumulosus sediment toxicity tests onvarious SBF base fluids with natural and formulated sediments. Nearlyall the SBF base fluids have lower sediment toxicity than diesel andmineral oil. Some SBF base fluids, however, show greater sedimenttoxicity than other SBF base fluids (see 65 FR 21550; Docket No. W-98-26, Record No. IV.A.a.13). The base fluids meeting this limitationinclude vegetable esters, low viscosity esters, internal olefins, andsome PAOs (see 65[[Page 6871]]FR 21550; Docket No. W-98-26, Record No. IV.A.a.13).    EPA finds this limit to be technically available and economicallyachievable through product substitution because information in therulemaking record supports the findings that vegetable esters, lowviscosity esters, and internal olefins have performance characteristicsenabling them to be used in the wide variety of drilling situations inoffshore U.S. waters and meet today's promulgated limit.    EPA selected the C16-C18 IO, which is themost popular drilling fluid in the GOM, as the basis for the sedimenttoxicity rate ratio limitation instead of the vegetable ester or lowviscosity ester for several reasons: (1) EPA does not believe thatvegetable esters can be used in all drilling situations; and (2) EPAdoes not have sufficient field testing information that low viscosityesters can be used in all drilling situations (see Section V.F.1.a). Inaddition, because of the uncertainty about ester performance, operatorsmay not be encouraged to switch from OBFs or WBFs to SBF when properlyinstalled and maintained. Specifically, vendor supplied data associatedwith these cuttings dryer deployments suggest that the overall cuttingsdryer downtime (i.e., time when cuttings dryer equipment is notoperable) is approximately 1 to 2% (Docket No. W-98-26, Record No.IV.A.a.6). EPA finds this small downtime percentage as acceptable.    EPA discussed how it revised the BAT/NSPS-level solids controlequipment configuration used in its analyses in the April 2000 NODA (65FR 21559). EPA also discussed a range of management options regardingthe BAT limitation for SBF retention on SBF-cuttings: (1) Twodischarges from the BAT/NSPS-level solids control equipmentconfiguration (i.e., one discharge from the cuttings dryer and anotherdischarge from the fines removal unit); (2) one discharge from the BAT/NSPS-level solids control equipment configuration (i.e., one dischargefrom the cuttings dryer with the fines from the fines removal unitcaptured for zero discharge); and (3) zero discharge of SBF-cuttings.These three options are labeled as BAT/NSPS Option 1, BAT/NSPS Option2, and BAT/NSPS Option 3, respectively. EPA estimates that 97% and 3%of the total cuttings are generated by cuttings dryer and fines removalunit, respectively.    EPA developed two numerical well averaged ROC limitations (i.e.,one for SBFs with the stock base fluid performance similar to estersand another for SBFs with the stock base fluid performance similar toC16-C18 internal olefins) and based both of theseROC limitations on the technology of only one discharge from thecuttings dryer with the fines from the fines removal unit captured forzero discharge (i.e., BAT/NSPS Option 2). The numerical well averagedROC maximum limitation for SBFs (i.e., 9.4%) with the environmentalcharacteristics of esters is based on a combination of data fromhorizontal centrifuge, vertical centrifuge, squeeze press, and High-Glinear shaker cuttings dryer technologies. The numerical well averagedROC maximum limitation for SBFs (i.e., 6.9%) with the environmentalcharacteristics of C16-C18 internal olefins isbased on a combination of data from horizontal and vertical centrifugecuttings dryer technologies. EPA estimates that operators, generallyinstalling new equipment where none has been used in the past, will beable to choose from among the better technologies, designs, operatingprocedures, and maintenance procedures that EPA has considered to beamong the best available technologies. EPA data demonstrates thatoperators properly using these cuttings dryer technologies will be ableto comply with these final ROC numerical limitations. Data submitted toEPA show that operators using the vertical centrifuge and horizontalcentrifuge are capable of achieving the lower ROC limitation (i.e.,6.9%). Data submitted to EPA also show that operators using thevertical centrifuge, horizontal centrifuge, squeeze press, and High-Glinear shaker are capable of achieving the higher ROC limitation (i.e.,9.4%). More details on the observed performance of the individualtechnologies and details of calculation for the numerical limits arepresented in the SBF Statistical Support Document and SBF DevelopmentDocument.    EPA developed the two ROC limitations because EPA used a two partapproach to control SBF-cuttings discharges. The first part is thecontrol of which SBF are allowed for discharge through use of stocklimitations (e.g., sediment toxicity, biodegradation, PAH content,metals content) and discharge limitations (e.g., diesel oilprohibition, formation oil prohibition, sediment toxicity, aqueoustoxicity). The second part is the control of the quantity of SBFdischarged with SBF-cuttings. As previously stated, EPA and industrysediment toxicity and biodegradation laboratory studies show that bothvegetable esters and low viscosity esters have better environmentalperformance than all other SBF base fluids. However, because thetechnical availability of product substitution with esters was notdemonstrated across the offshore subcategory, EPA rejected the optionof basing sediment toxicity and biodegradation stock limitations andstandards on vegetable esters and low viscosity esters (see V.F.1.a).EPA is sufficiently satisfied, however, that both esters provide betterenvironmental performance (e.g., sediment toxicity, biodegradation).Consequently, EPA is promulgating a higher retention on cuttingsdischarge limitation to encourage operators to use esters whenpossible. EPA estimates that a higher retention on cuttings dischargelimitation for esters is equivalent to the same level of control as alower retention on cuttings discharge limitation for all other SBFsthat have poorer sediment toxicity and biodegradation performances.    In response to the April 2000 NODA, EPA received comments from anester-based SBF manufacturer that EPA should create an incentive foroperators to use ester-based SBFs by basing the ROC limitation forester-based SBFs on baseline solids control equipment (e.g., primaryand secondary shale shakers, fines removal unit) (Docket No. W-98-26,Record No. IV.A.a.7). In late comments, this same commentor claimedthat a ROC limitation based on any cuttings dryer technology would notprovide any incentive for the use of ester-based SBFs (Docket No. W-98-26, Record No. IV.A.a.38). Further, they argued that the superiorlaboratory performance of these ester base fluids in terms of sedimenttoxicity and biodegradation justifies allowing them to be dischargedwith a ROC limitation based on baseline solids control equipment. EPAestimates that a ROC BAT limitation based on the baseline solidscontrol equipment is above 15.3%.    While EPA is willing to expand the technology basis to allow theuse of less effective cuttings dryers for ester-based SBFs (e.g.,squeeze press, High-G linear shakes), EPA is unwilling to entirelyabandon the use of cuttings dryers for ester-based SBF drillingoperations. EPA is unwilling to set a higher ROC limitation for SBFswith the environmental performance of ester-based SBFs based onbaseline solids control technology because the environmentalimprovement resulting from the use of improved solids controltechnology (i.e., cuttings dryers) outweighs the incremental esterlaboratory sediment toxicity and biodegradation performance overinternal olefins. Cuttings dryers promote pollution prevention throughincreased re-use of drilling fluids and prevent[[Page 6872]]significant amounts of pollutants from being discharged to the ocean.    EPA provides for variability from the long term average (LTA) ofperformance data from the candidate treatment technology ortechnologies. The LTA performance of the baseline solids controltechnology is 10.2%, as compared to the LTA of 4.8% based on data fromall four cutting dryer technologies. This difference translates to 118million pounds per year of pollutants being discharged using theexisting and new model well counts for the selected BAT option (i.e.,BAT/NSPS Option 2) (see SBF Development Document). Further, aspreviously stated in the April 2000 NODA (65 FR 21553), field resultsshow that: (1) Cuttings are dispersed during transit to the seabed andno cuttings piles are formed when SBF concentrations on cuttings areheld below 5%; and (2) cuttings discharged from cuttings dryers (withSBF retention values under 5%) in combination with a sea water flush,hydrate very quickly and disperse like water-based cuttings. Thus,while EPA is willing to provide additional flexibility to dischargersof ester-based fluids, EPA believes that the appropriate technologybasis that reflects BAT is cuttings dryers technology. In balancing theenvironmental effects of these additional ester-based SBFs dischargescontrolled with the use of baseline solids control technology againstthe environmental effects of lower internal olefin-based SBFsdischarges controlled with the use of cuttings dryers, EPA hasconcluded that the improvement in solids control technology leading tolower values of ROC is a more significant factor than laboratory datafor ester base fluids showing lower sediment toxicity and higherbiodegradation.    EPA is also not convinced that the difference in ROC limitationsprovides no incentive to use ester-based SBFs, as the ester-based SBFmanufacturer argues. EPA believes that the difference between 6.9% and9.4% could provide an incentive for operators to use ester-based SBFs.As operators have increasingly installed cuttings dryers in the GOM(over three dozen successful deployments in the last two years), and asany SBF discharger installs new technology to comply with the lower ROClimitation (i.e., 6.9%), operators may find that it is worthwhile topurchase ester-based SBFs in order to be able to operate with even agreater margin of flexibility under a limit of 9.4% as compared to6.9%.    As this rule is performance based, EPA is not prohibiting thedischarge of SBF-cuttings from the fines removal unit in order tocomply with the base fluid retained on cuttings discharge BATlimitation. Operators are only required to show that the volumeweighted average of all their SBF-cuttings discharges is below thedischarge BAT limitation. EPA expects that most operators will be ableto discharge cuttings from the cuttings dryer and fines removal unitand comply with this discharge BAT limitation. If, for example, theaverage retention of SBF on SBF-cuttings from a cuttings dryer is6.00%, the average retention of SBF on SBF-cuttings from a finesremoval unit is 12.00%, and the fines are observed to comprise 3% ofthe total cuttings discharged, then the well average is 6.18% (i.e.,(0.97) (6.00%) + (0.03)(12.00%) = 6.18%). If the well average for SBFretention from the cuttings dryer exceeds the discharge limit then inorder to comply with this discharge BAT limitation all cuttings must bere-injected on-site or hauled to shore for land disposal. EPA findsthat if this is the case, the limit is technologically availablebecause operators have transported OBFs to shore since 1986 and havetransported WBFs that do not meet the existing effluent limitations andstandards since 1993.    EPA finds that both ROC limitations (i.e., 6.9%, 9.4%) aretechnically available to the industry because they are based on productsubstitution and a statistical analysis of ROC performance fromdrilling conditions throughout offshore waters. The BAT limitations forcontrolling the amount of SBF discharged with SBF-cuttings arecalculated such that nearly all well averages for retention areexpected to meet these values using the selected technologies withoutany additional attention to design, operation, or maintenance. EPA datademonstrates that operators properly using these cuttings dryertechnologies will be able to comply with these final ROC numericallimitations because: (1) These limits allow for variation in formationcharacteristics that may not exist in the United States; (2) operators,generally installing new equipment where none has been used in thepast, will be able to choose from among the better technologies,designs, operating procedures, and maintenance procedures that EPAconsiders to be among the best available technologies; and (3)operators may elect to use SBFs with the stock base fluid performanceof esters and horizontal or vertical centrifuge cuttings dryers toachieve a ROC well average well below the 9.4% ROC limitation.    Data used in the calculation of the numerical limits excluderetention results submitted without backup calculations (i.e., withoutraw retort data) and include data from drilling operations in foreignwaters (e.g., Canada). EPA excluded ROC data without raw retort data(e.g., masses and volumes of cuttings samples and recovered liquidstaken during the retort method by the field technician) due to concernsover data quality (e.g., no independent method to check data quality).EPA included ROC data from Canadian drilling operations to incorporatethe variability of cuttings dryer performance in harder and lesspermeable formations that generally lead to higher ROC values. EPAestimates that the major factors leading to higher ROC values for allsolids control equipment include: (1) Slower rates of penetration; (2)formations that are harder and less permeable; and (3) selection ofcertain drill bits. The Canadian ROC data come from formations that aregenerally much harder and less permeable than what is observed in theGOM. These harder formations generally lead to slower rates ofpenetration. The less permeable Canadian formations lead to fewerdownhole losses of SBF. Downhole losses require the addition of freshSBF to maintain volume requirements for the active mud system. Theseadditions of fresh SBF to the active mud system help control thepotential of build-up of fines. In addition, operators often use PDCdrill bits in order to grind through the hard Canadian formations. Thisgrinding action leads to smaller cuttings than is what is observed inthe GOM. The smaller cuttings have more surface area for SBF thanlarger cuttings and generally have higher ROC values. Consequently,EPA's use of Canadian data in its analyses incorporate sufficientvariability to model the formations in GOM, Offshore California, CookInlet, Alaska, and other offshore U.S waters where EPA does not haveROC data.    EPA finds that both well-average discharge BAT ROC limitations(e.g., 6.9%, 9.4%) for base fluid on wet cuttings are economicallyachievable. According to EPA's analysis, in addition to reducing thedischarge of SBFs associated with the cuttings, EPA estimates that thiscontrol will result in a net savings of $48.9 million ($1999) dollarsper year. This savings results, in part, because the value of the SBFrecovered is greater than the cost of installation of the improvedsolids control technology.    EPA concluded that a zero discharge requirement for SBF-cuttingsfrom[[Page 6873]]existing sources and the subsequent increase use of OBFs and WBFs wouldresult in: (1) Unacceptable NWQIs; and (2) more pollutant loadings tothe ocean due to operators switching from SBFs to less efficient WBFs(see Sections II.B and V.F). For these reasons, EPA rejected the BATzero discharge option for SBF-cuttings from existing sources.    EPA also requested comments in the April 2000 NODA (65 FR 21570) onthe issue of rig compatibility with the installation of cuttings dryers(e.g., vertical or horizontal centrifuges, squeeze press mud recoveryunits, High-G linear shakers). EPA received general information on theproblems and issues related to cuttings dryer installations from API/NOIA stating that not all rigs are capable of installing cuttingsdryers (Docket No. W-98-26, Record No. IV.A.a.13). In late comments,some industry commentors asserted that 48 of the 223 GOM drilling rigsare not capable of having a cuttings dryer system installed due toeither rig space and/or rig design without prohibitive costs or rigmodifications (Docket No. W-98-26, Record No. IV.B.b.33). Upon afurther, more extensive review of GOM rigs, these same commentorsasserted that 30 of 234 GOM drilling rigs are not capable of having acuttings dryer system installed due to either rig space and/or rigdesign without prohibitive costs or rig modifications (Docket No. W-98-26, Record No. IV.B.b.34). EPA also received late comments from oneoperator, Unocal, stating that 36 of 122 Unocal wells drilled betweenlate 1997 and mid-2000 were drilled with rigs that do not have 40 footx  40 foot space available which they assert is necessary for acuttings dryer installation (Docket No. W-98-26, Record No. IV.B.b.31).The API/NOIA rig survey and the Unocal rig survey identified most ofthe same rigs as unable to install cuttings dryers. However, two rigs(i.e., Parker 22, Nabors 802) identified in the Unocal rig survey ashaving no space for a cuttings dryer installation were identified inthe API/NOIA rig survey as each having a previous cuttings dryerinstallation. Unocal requested in late comments that EPA subcategorizecertain rigs from being subject to the retention limit or that theserigs be able to discharge SBFs using performance that reflects currentshale shaker technology (Docket No. W-98-26, Record No. IV.A.a.36).    Based on the record, EPA finds that current space limitations forcuttings dryers do not require a 40 foot  x  40 foot space.Specifically, EPA has in the record information gathered during EPA'sOctober 1999 site visit and information supplied by API/NOIA, MMS, andequipment vendors. EPA received information from a drilling fluidmanufacturer and cuttings dryer equipment vendor, M-I Drilling Fluids,stating that they are not aware of any GOM rig not capable ofinstalling a cuttings dryer (Docket No. W-98-26, Record No. IV.B.b.32).Another cuttings dryer equipment vendor, JB Equipment, asserted thatthere are at most only a few rigs that pose questionable installationproblems and that they have yet to survey a rig that they could notinstall a cuttings dryer (Docket No. W-98-26, Record No. IV.B.b.48). JBEquipment also stated that inexperience with cuttings dryerinstallations may inhibit the ability of operators or rig owners toproperly judge whether a cuttings dryer can be installed. JB Equipmentcited an example where the operator concluded that a cuttings dryercould not be installed on a rig (Nabors 803) while JB Equipmentsurveying efforts identified the cuttings dryer installation for thesame rig as one of the simplest installations JB Equipment performs.MMS also concluded that rigs do not need a 40 foot  x  40 foot space toinstall a cuttings dryer and that, with the exception of a few jackupand platform rigs, there should not be any significant issues relatedto installing cuttings dryers on OCS drilling rigs (Docket No. W-98-26,Record No. IV.B.a.28). API/NOIA estimated that 150 square feet arerequired for a cuttings dryer installation in order to meet the ROC BATlimitation and NSPS (Docket No. W-98-26, Record No. IV.A.a.13). EPAalso estimates that the minimum height clearance for a typical cuttingsdryer installation is 6 feet (see SBF Development Document). The API/NOIA estimate is based on the installation of a horizontal centrifugecuttings dryer (i.e., MUD-6). The Unocal estimate is based on thevertical centrifuge cuttings dryer and is also characterized by otherindustry representatives and MMS as too high (Docket No. W-98-26,Record No. IV.B.b.34; Record No. IV.B.a.28). EPA's estimate of atypical vertical centrifuge installation is 15 feet  x  15 feet (i.e.,225 square feet) with a minimum height clearance of 11 feet (see SBFDevelopment Document). EPA based the ROC BAT limitation and NSPS (e.g.,6.9%) on the use of both these cuttings dryers for SBFs with the stocklimitations of C16-C18 IOs. Based on commentsfrom operators, equipment vendors, and MMS, EPA believes that most ofthese shallow water rigs have the requisite 150-225 square feetavailable to install a cuttings dryer (see SBF Development Document).Therefore, EPA finds that operators are not required to have a 1,600square foot space for a cuttings dryer installation in order to meetthe ROC BAT limitation and NSPS. Proper spacing and placement ofcuttings dryers in the solids control equipment system should preventinstallation problems.    Because of the large discrepancy between EPA's record informationand the space requirements asserted by the commenter (1,600 square feetversus EPA's 225 square feet + 11 feet in height for the verticalcentrifuge or 150 square feet + 6 feet in height for the horizontalcentrifuge--MUD-6), EPA does not necessarily believe that there are asmany wells that cannot install cuttings dryers as the commentor(Unocal) claims. Further, based on scant detail supporting theseassertions, and their lateness in the process, EPA has no basis uponwhich to assess them or verify them.    Moreover, EPA does not believe that it has enough information toreasonably subcategorize these facilities, nor did it have time toprovide public notice of how it would define such a subcategory, giventhe court-ordered deadline for this rule. EPA does not believe thatbasing a subcategory by specifying a space requirement alone (e.g.operators that do not have a certain amount of deck space available on,below or adjacent to the deck would not be subject to this requirement)would be sufficient to prevent operators from configuring their otherequipment in a manner that would enable them to fit into thesubcategory. Such an exception might also lead to operators to makeother assertions justifying that they should be included (e.g., thatwhile they have a certain amount of space available, safety reasonsprevent placement of the technology on the rig). Without a solution tothese issues, EPA is concerned that such a subcategorization wouldpotentially be too broad and be unworkable.    For these reasons, EPA believes that the appropriate way to handlethese concerns is through the fundamentally different factors (FDF)variance process. This process, provided for under CWA section 301(n),would allow operators to submit supporting data and information to EPAand would give the public the opportunity to comment on that data todetermine whether an FDF is truly warranted for that drilling facility.EPA has authority over owners and operators, who are both dischargers,but the NPDES regulations require the operator to apply for the NPDESpermit: ``When a facility or activity is owned by one person but isoperated by another person, it is the operator's duty to obtain[[Page 6874]]a permit,'' (see 40 CFR 122.21(b)). Thus, mobile drill rig``operators'' as dischargers can apply for FDFs (see 40 CFR 125.32;122.21(b)).    EPA notes that the ROC limitations and standards do not precludethe use of SBFs if an operator cannot meet them if the operator canmeet zero discharge through re-injection or shipment to shore.Historically, dischargers have used water-based fluids in shallow waterwells and this may also be an option. EPA considers controlled WBFdischarges preferable to uncontrolled SBF discharges. EPA examined theNWQIs associated with these zero discharge operations as acceptable(see SBF Development Document). The NWQIs of zero discharge for theshallow water wells are much smaller that those associated for theentire region covered by this rule. Further, while a SBF-cuttingsdischarge option with adequate controls is preferred over the zerodischarge option for SBF-cuttings in U.S. Offshore waters, a SBF-cuttings discharge option with inadequate controls is not preferredover zero discharge. The retention limit is a very important controlbecause it controls: (1) The amount of SBF discharged to the ocean; (2)the biodegradation rate of discharged SBF; and (3) the potential forSBF-cuttings to develop cuttings piles and mats which are detrimentalto the benthic environment. In short, EPA does not view existing shaleshaker technology (or performance of other technology equivalent toshale shaker technology) to constitute the appropriate level of controlunder BAT or BADT (NSPS).    EPA has also decided that solids accumulated at the end of the well(``accumulated solids'') and wash water used to clean out accumulatedsolids or on the drill floor are associated with drill cuttings and aretherefore not controlled by the zero discharge requirement for SBFs notassociated with drill cuttings (see Section V.C). EPA has decided tocontrol accumulated solids and wash water under the dischargerequirements for cuttings associated with SBFs. The amount of SBF basefluid discharged with discharged accumulated solids will be estimatedusing procedures in Appendix 7 to subpart A of 40 CFR part 435 andincorporated into the base fluid retained on cuttings numericlimitation or standard. The source of the pollutants in the accumulatedsolids and associated wash water are drill cuttings and drilling fluidsolids (e.g., barite). The drill cuttings and drilling fluid solids canbe prevented from discharge with SBF-cuttings due to equipment design(e.g., sand traps, sumps) or improper maintenance of the equipment(e.g., failing to ensure the proper agitation of mud pits). EPA agreeswith commentors that the discharge of SBF associated with accumulatedsolids in the SBF active mud system and the associated wash water isnormally a one-time operation performed at the completion of the SBFwell (e.g., cleaning out mud pits and solids control equipment).    The quantity of SBF typically discharged with accumulated solidsand wash water is relatively small. The SBF fraction in the 75 barrelsof accumulated solids is approximately 25% and generally only verysmall quantities of SBF are contained in the 200 to 400 barrels ofassociated equipment wash water. Current practice is to retainaccumulated solids for zero discharge or recover free oil fromaccumulated solids prior to discharge. Since current practice is torecover free oil and discharge accumulated solids, the controlleddischarge option for SBF-cuttings represents current practice and iseconomically achievable. Moreover, recovering free oil from accumulatedsolids prior to discharge has no unacceptable NWQIs. EPA definesaccumulated solids and wash water as associated with drill cuttings.Therefore, operators will control these SBF-cuttings wastes using theSBF stock limitations and cuttings discharge limitations. As compliancewith EPA's SBF stock limitations and cuttings discharge limitationsdoes not require the processing of all SBF-cuttings wastes through thesolids control technologies (e.g., shale shakers, cuttings dryers,fines removal units), operators may or may not elect to processaccumulated solids or wash water through the solids controltechnologies.    EPA is also promulgating a set of BMPs for operators to use thatdemonstrates compliance with the numeric ROC limitation and thereforereduces the retort monitoring otherwise required to determinecompliance with the numeric ROC limitation. This option combines theset of BMPs that represent current practice with BMPs that areassociated with the use of improved solids control technology. Thisoption is technologically available and economically achievable for thesame reasons that apply to compliance with the ROC numericallimitations. Examples of BMPs that represent current practices are, forexample, use of mud guns, proper mixing procedure, elimination ofsettling places for accumulated solids. Examples of BMPs associatedwith the use of the new solids control technology are, for example,operating cuttings dryers in accordance with the manufacturer'sspecifications and maintaining a certain mass flux. If operators electto use this BMP option, they will be required to demonstrate compliancethrough limited retort monitoring of cuttings and additional BMPpaperwork. Paperwork requirements are detailed in Appendix 7 of subpartA of 40 CFR part 435. Paperwork cost and burden estimates are detailedin Section IX.D of the preamble.    d. Sediment Toxicity of SBF Discharged with Cuttings. As originallyproposed in February 1999 (64 FR 5491) and re-stated in April 2000 (65FR 21557), EPA is today promulgating a BAT limitation to control themaximum sediment toxicity of the SBF discharged with cuttings. This BATlimitation controls the sediment toxicity of the SBF discharged withcuttings as a non-conventional pollutant parameter and as an indicatorfor other pollutants in the SBF discharged with cuttings. Some of thetoxic, priority, and non-conventional pollutants in the SBF dischargedwith cuttings may include: (1) The base fluids such as enhanced mineraloils, internal olefins, linear alpha olefins, poly alpha olefins,paraffinic oils, C12-C14 vegetable esters of 2-hexanol and palm kernel oil, ``low viscosity'' C8 esters,and other oleaginous materials; (2) barite which is known to generallyhave trace contaminants of several toxic heavy metals such as mercury,cadmium, arsenic, chromium, copper, lead, nickel, and zinc; (3)formation oil which contains toxic and priority pollutants such asbenzene, toluene, ethylbenzene, naphthalene, phenanthrene, and phenol;and (4) additives such as emulsifiers, oil wetting agents, filtrationcontrol agents, and viscosifiers.    The sediment toxicity of the SBF discharged with cuttings ismeasured by the modified sediment toxicity test (i.e., ASTM E1367-92:``Standard Guide for Conducting 10-day Static Sediment Toxicity TestsWith Marine and Estuarine Amphipods'' (incorporated by reference andavailable from ASTM, 100 Bar Harbor Drive, West Conshohocken, PA19428), supplemented with the preparation procedure specified inAppendix 3 of subpart A of 40 CFR part 435) using a natural sediment orformulated sediment, 96-hour testing period, and Leptocheirusplumulosus as the test organism. EPA is today promulgating a sedimenttoxicity limitation for the SBF discharged with cuttings at the pointof discharge that would only allow the discharge of SBF-cuttings usingSBFs as toxic or less toxic, but not more toxic, than C16-C18[[Page 6875]]IOs SBFs. Alternatively, this limitation could be expressed in terms ofa ``SBF sediment toxicity ratio'' which is defined as 96-hourLC50 of C16-C18 internal olefins SBFdivided by the 96-hour LC50 of the SBF being discharged withcuttings at the point of discharge. EPA is promulgating a SBF sedimenttoxicity ratio of less than 1.0.    EPA finds that the sediment toxicity test at the point of dischargeis practical as an indicator of the sediment toxicity of the drillingfluid at the point of discharge. As previously stated, establishingdischarge limits on toxicity encourages the use of less toxic drillingfluids and additives. The modifications to the sediment toxicity testinclude shortening the test to 96-hours. Shortening the test will allowoperators to continue drilling operations while the sediment toxicitytest is being conducted on the discharged drilling fluid. Moreover,discriminatory power is substantially reduced for the 10-day test ondrilling fluid as compared to the 96-hour test (i.e., the 10-day testis of lower practical use in determining whether a SBF is substantiallydifferent from OBFs). Finally, operators discharging WBFs are alreadycomplying with a biological test at the point of discharge, the 96-hourSPP toxicity test, which tests whole WBF aquatic toxicity using thetest organism Mysidopsis bahia.    The promulgated sediment toxicity limitation would be achievablethrough product substitution. EPA anticipates that the base fluidsmeeting the sediment toxicity limitation would include vegetableesters, low viscosity esters, and internal olefins. The referenceC16-C18 IOs SBF will be formulated to meet thespecifications in Table 1 and also contained in Appendix 8 of subpart Aof 40 CFR part 435. The sediment toxicity discharge limitation istechnically and economically achievable because it is based oncurrently available base fluids that can be used and are used acrossthe wide variety of drilling situations found in U.S. offshore waters.EPA estimates minimal monitoring costs associated with this limitation.Additionally, the sediment toxicity discharge limitation will not leadto an increase of NWQIs.         Table 1.--Properties for Reference C16-C18 IOs SBF Used in Discharge Sediment Toxicity Testing----------------------------------------------------------------------------------------------------------------                                                                                          Reference C16-C18 ISOsMud weight of SBF discharged with cuttings (pounds per gallon)   Reference C16-C18 IOs    SBF synthetic to water                                                                SBF (pounds per gallon)         ratio (%)----------------------------------------------------------------------------------------------------------------8.5-11........................................................                      9.0                    75/2511-14.........................................................                     11.5                    80/20> 14..........................................................                     14.5                    85/15================================================================================================================Plastic Viscosity (PV), centipoise (cP).......................  .......................                    12-30Yield Point (YP), pounds/100 sq. ft...........................  .......................                    10-2010-second gel, pounds/100 sq. ft..............................  .......................                     8-1510-minute gel, pounds/100 sq. ft..............................  .......................                    12-30Electrical stability, V.......................................  .......................                    > 300----------------------------------------------------------------------------------------------------------------G. NSPS Technology Options Considered and Selected for Drilling FluidAssociated with Drill Cuttings    The general approach followed by EPA for developing NSPS optionswas to evaluate the best demonstrated SBFs and processes for control ofpriority toxic, non-conventional, and conventional pollutants.Specifically, EPA evaluated the technologies used as the basis for BPT,BCT and BAT. The Agency considered these options as a starting pointwhen developing NSPS options because the technologies used to controlpollutants at existing facilities are fully applicable to newfacilities.    EPA has not identified any more stringent treatment technologyoption which it considered to represent NSPS level of controlapplicable to the SBF-cuttings wastestream. Further, EPA has made afinding of no barrier to entry based upon the establishment of thislevel of control for new sources. Therefore, EPA is promulgating thatNSPS be established equivalent to BPT and BAT for conventional,priority, and non-conventional pollutants. EPA concluded that NSPS aretechnologically and economically achievable for the same reasons thatBAT is available and BPT is practical. EPA also concluded that NWQIsare reduced under the selected NSPS for new wells due to the increasedefficiency of SBF drilling.    EPA concluded that a zero discharge requirement for SBF-cuttingsfrom new sources and the subsequent increased use of OBFs and WBFswould result in: (1) unacceptable NWQIs; and (2) more pollutantloadings to the ocean due to operators switching from SBFs to lessefficient WBFs (see Sections II.B and V.F).    For the same reasons that the BAT limitations promulgated intoday's rule are technologically and economically achievable, thepromulgated NSPS are also technologically and economically achievable.EPA's analyses show that under the SBF zero discharge option for allareas as compared to current practice as a basis for new sourcestandards there would be an increase of 3.4 million pounds of cuttingsannually shipped to shore for disposal in NOW sites and an increase of10.2 million pounds of cuttings annually injected. This zero dischargeoption would lead to an increase in annual fuel use of 18,067 BOE andan increase in annual air emissions of 528 tons. Finally, the SBF zerodischarge option for the GOM would lead to an increase of 7.5 millionpounds of WBF-cuttings being discharged to U.S. Offshore waters. Thispollutant loading increase is a result of operators in U.S. Offshorewaters (in the GOM) switching from efficient SBF drilling to lessefficient WBF drilling. EPA found these levels of NWQIs unacceptableand rejected the NSPS zero discharge option for SBF-cuttings from newsources, except in Coastal Cook Inlet, Alaska.H. PSES and PSNS Technology Options    EPA is not establishing pretreatment standards for the facilitiescovered by this rule. Based on information in the record, EPA has notidentified any existing offshore or Cook Inlet coastal oil and gasextraction facilities that discharge SBF and SBF-cuttings to publiclyowned treatment works (POTWs), nor are any new facilities projected todirect these wastes in such manner.[[Page 6876]]I. Best Management Practices (BMPs) to Demonstrate Compliance withNumeric BAT Limitations and NSPS for Drilling Fluid Associated withDrill Cuttings    Sections 304(e), 308(a), 402(a), and 501(a) of the CWA authorizethe Administrator to prescribe BMPs as part of effluent limitationsguidelines and standards or as part of a permit (see Section II.A.7).The BMP alternatives to numeric limitations and standards in this finalrule are directed, among other things, at preventing or otherwisecontrolling leaks, spills, and discharges of toxic and hazardouspollutants in SBF cuttings wastes (see 65 FR 21569 for a list of thetoxic and hazardous pollutants controlled by these BMPs).    As discussed in the April 2000 NODA (65 FR 21568), EPA consideredthree options for the final rule for the BAT limitation and NSPScontrolling SBF retained on discharged cuttings: (1) A single numericdischarge limitation with an accompanying compliance test method; (2)allowing operators to choose either a single numeric dischargelimitation with an accompanying compliance test method, or as analternative, a set of BMPs that employs limited cuttings monitoring; or(3) allowing operators to choose either a single numeric dischargelimitation with an accompanying compliance test method or analternative set of BMPs that employ no cuttings monitoring. Under thethird BMP option for SBF-cuttings (i.e., cuttings discharged and notmonitored), EPA also considered whether to require as part of the BMPoption, the use of a cuttings dryer as representative of BAT/NSPS or tomake the use of a cuttings dryer optional.    EPA selects the second BMP option (i.e., allowing operators tochoose either a single numeric discharge limitation with anaccompanying compliance test method, or as an alternative, a set ofBMPs that employs limited cuttings monitoring) in the final rule. EPAselects this option as it provides for a reasonable level offlexibility and is based on quantifiable performance measures. EPAanalyses show that cuttings monitoring for the first third of the SBFfootage drilled for a SBF well interval is a reliable indicator of theremaining two-thirds of the SBF-interval (see SBF Statistical SupportDocument; Docket No. W-98-26, Record No. III.B.a.18; Record No.III.B.b.15). Procedures for demonstrating compliance with the selectedBMP option are given in Appendix 7 to subpart A of part 435.    For the final rule, EPA did not have enough data from across a widevariety of drilling conditions (e.g., formation, water depth, rig size)to demonstrate that BMPs without cuttings monitoring are equivalent toa numeric ROC limitation or standard. EPA is also concerned that a setof BMPs without cuttings monitoring is not as objective to enforce.This is because with a numeric limitation or with the selected BMPoption with reduced cuttings monitoring, operators will need to keeprecords demonstrating compliance with the numeric limitation. Bycontrast, under a BMP option with no numeric limit, there is noobjective performance measure. This presents a particular problemoffshore, where real-time inspections are not as practical as on landbased industries. Therefore, EPA rejected the third BMP option andcuttings dryer sub-option for SBF-cuttings (i.e., allowing operators tochoose either a single numeric discharge limitation with anaccompanying compliance test method or an alternative set of BMPs thatemploy no cuttings monitoring). EPA concluded that BMP option one andBMP option two demonstrate the same level of compliance with the wellaveraged ROC limitation and standard (see SBF Statistical SupportDocument). Therefore, EPA selected BMP option two over BMP option oneto provide operators with greater flexibility to demonstrate compliancewith the well averaged ROC limitation and standard.    The BMP option promulgated in this final rule includes informationcollection requirements that are intended to control the discharges ofSBF in place of numeric effluent limitations and standards. Theseinformation collection requirements include, for example: (1) Trainingpersonnel; (2) analyzing spills that occur; (3) identifying equipmentitems that might need to be maintained, upgraded, or repaired; (4)identifying procedures for waste minimization; (4) performingmonitoring (including the operation of monitoring systems) to establishequivalence with a numeric cuttings retention limitation and to detectleaks, spills, and intentional diversion; and (5) generally toperiodically evaluate the effectiveness of the BMP alternatives.    BMP option two also requires operators to develop and, whenappropriate, amend plans specifying how operators will implement BMPoption two, and to certify to the permitting authority that they havedone so in accordance with good engineering practices and therequirements of the final regulation. The purpose of those provisionsis, respectively, to facilitate the implementation of BMP option two ona site-specific basis and to help the regulating authorities to ensurecompliance without requiring the submission of actual BMP Plans.Finally, the recordkeeping provisions are intended to facilitatetraining, to signal the need for different or more vigorouslyimplemented BMP alternatives, and to facilitate compliance assessment.Details on burden and cost estimates associated with these additionalpaperwork requirements are discussed in Section IX.D.VI. Costs and Pollutant Reductions for Final RegulationA. Compliance Costs    EPA has analyzed the compliance costs and incremental compliancecosts or savings beyond current industry practices and requirements, aswell as pollutant loadings and incremental loadings or reductions, EPAhas performed these analyses for the Gulf of Mexico, offshoreCalifornia, and coastal Cook Inlet, Alaska, for baseline (current)costs and three control option costs. (Compliance costs were notdeveloped for other offshore regions in Alaska where oil and gasproduction activity exists because discharges of drill cuttings is notexpected to occur in these areas.) The three technology-based optionsconsidered are: (1) BAT/NSPS Option 1 (controlled discharge option withdischarges from the cuttings dryer and fines removal unit); (2) BAT/NSPS Option 2 (controlled discharge option with discharges from thecuttings dryer but not the fines removal unit); and (3) BAT/NSPS Option3 (Zero Discharge Option). Compliance costs/savings and pollutantincreases/reductions are based on: (1) Projected annual drillingactivity in the three geographic regions; (2) model well volumes andwaste characteristics; and (3) technology and monitoring costs.    The compliance cost analysis begins with the development of definedpopulations of wells on a regional and well-type basis, develops per-well estimates from an analysis of line-item costs, and then aggregatescosts into total regional and well-type costs by applying per wellcosts to appropriate populations of wells. EPA estimates baselinecompliance costs for current industry waste management practices andfor compliance with each regulatory option. EPA then calculatedincremental compliance costs, which reflect the difference betweencompliance costs for a regulatory option and baseline compliance costsand the net compliance costs or savings which incorporate the costsalong with savings realized by recovering drilling fluids and moreefficient drilling. Tables 2 and[[Page 6877]]3, for existing and new sources respectively, list the total annualbaseline costs, compliance costs, incremental compliance costs, costsavings, and net incremental compliance costs, calculated for eachgeographic area and regulatory option.1. Large Volume DischargesBILLING CODE 6560-50-U[[Page 6878]][GRAPHIC] [TIFF OMITTED] TR22JA01.154[[Page 6879]][GRAPHIC] [TIFF OMITTED] TR22JA01.155[GRAPHIC] [TIFF OMITTED] TR22JA01.156[[Page 6880]][GRAPHIC] [TIFF OMITTED] TR22JA01.1572. Small Volume Discharges    As previously stated, EPA learned that SBF is controlled with zerodischarge at the drill floor, in the form of vacuums and sumps toretrieve spilled fluid and associated wash water. EPA also learned thatapproximately 75 barrels of fine solids and barite, which have anapproximate SBF content of 25%, can accumulate in the dead spaces ofthe mud pit, sand trap, and other equipment in the drilling fluidcirculation system. Current practice is to either wash these solids outwith water for overboard discharge, or to retain the waste solids fordisposal. Several hundred barrels (approximately 200 to 400 barrels) ofwater are used to wash out the mud pits. Industry representatives alsoindicated to EPA that those oil and gas extraction operations thatdischarge wash water and accumulated solids first recover free SBF.    No additional costs were considered for controlling the minorspills of SBF (e.g.,  5 gallons spilled during each drill stringconnection or disconnection) at the drill floor as: (1) Zero dischargepractices for recovering SBF at the drill floor during drilling are thecurrent practice; and (2) current practice is also to recover free SBFfrom the wash water used at the drill floor. Additionally, sincecurrent practice is to first recover free SBF from accumulated solidsand discharge the accumulated solids with wash water, no additionalcosts were[[Page 6881]]considered for controlling these discharges.    EPA did not select zero discharge for management of theseaccumulated solids and associated wash water. EPA is defining thesewastes as being associated with SBF-cuttings and subject to the samerequirements as other SBF discharges associated with SBF-cuttings. Inparticular, the final rule requires operators to first recover free oilfrom any accumulated solids or associated wash water prior todischarging the accumulated solids and associated wash water. Thesepractices are related to the current BPT limitations (i.e., nodischarge of free oil) and current industry practice using solidscontrol equipment in order to comply with the no free oil (sheen test)and SPP toxicity requirements. Accordingly, the requirement to recoverfree oil from accumulated solids and associated wash water prior todischarge is technologically and economically achievable with noadditional NWQIs. Retort monitoring will also be performed on theaccumulated solids and the retort monitoring results will beincorporated into the overall well-average SBF retained on cuttingsvalue as described in Appendix 7 of Subpart A of 40 CFR 435.B. Pollutant Reductions    The methodology for estimating pollutant loadings and incrementalpollutant loadings (reductions) effectively parallels that of thecompliance cost analysis. The pollutant loadings analysis uses datafrom EPA and industry sources that quantify the pollutantcharacteristics of drilling fluids and cuttings waste streams(typically in, or converted to, a per barrel basis). Waste volumes forthe four model well types (DWD, DWE, SWD, SWE) are coupled with theseper barrel pollutant quantities to obtain per well estimates ofpollutant loadings. These per well estimates are then coupled with thesame well count data as used in the cost analysis to derive well typeand aggregate regional pollutant loadings for the baseline and alloptions. Similar to the cost analysis, incremental loadings (orremovals) are obtained by difference between the estimated loadings ofeach option less baseline loadings, at both the BAT and NSPS level ofcontrol. This methodology is presented in more detail in the SBFDevelopment Document.    The loadings and non-water quality impacts of wastes subject tozero discharge limitations by this rule are important factors in itsdevelopment. Zero discharge wastes have two fates: they are injectedinto sub-seabed formations onsite or they are transported to shore fordisposal via land farming or injection. The allocation of zerodischarge wastes between onsite injection versus onshore disposalfollow the same well type and regional assumptions as were used for thecost analysis. Zero discharge loadings (removals) are determinedidentically to discharge loadings; they are presented in detail in theDevelopment Document and are summarized below.    Table 4 presents a summary of industry-wide results, by region, forBAT baseline loadings, both discharge options, and the zero dischargeoption, as well as their incremental loadings (removals). Table 5presents this information for new sources.    The BCT cost test evaluates the reasonableness of BCT candidatetechnologies as measured from BPT level compliance costs and pollutantreductions. The proposed BCT level of regulatory control is equivalentto the BPT level of control for both the discharge options and the zerodischarge option. If there is no incremental difference between BPT andBCT, there is no cost to BCT and thus the option passes both BCT costtests.[[Page 6882]][GRAPHIC] [TIFF OMITTED] TR22JA01.158[[Page 6883]]      Table 5.--Summary Annual SBF Pollutant Loadings, New Sources                            [In pounds/year]------------------------------------------------------------------------                                                 SBF pollutant loadings               Technology basis                   (reductions)--Gulf of                                                         Mexico------------------------------------------------------------------------Baseline/Current Practice Technology Loadings:    Discharge with LTA of 10.2% SBF ROC.......               17,405,127    Discharge of WBF and cuttings.............               92,903,606    Discharge of OBF..........................                        0                                               -------------------------      Total Baseline Loadings.................              110,308,733                                               =========================Technology Option Loadings:    BAT/NSPS Option 1.........................    Discharge with LTA of 4.03% SBF ROC.......               20,241,106    Discharge of WBF and cuttings.............               87,462,923    Discharge of OBF..........................                        0                                               -------------------------      Total NSPS 1 Loadings...................              107,704,029                                               =========================    BAT/NSPS Option 2.........................    Discharge with LTA of 3.82% SBF ROC.......               19,722,488    Discharge of WBF and cuttings.............               87,462,923    Discharge of OBF..........................                        0                                               -------------------------      Total NSPS 2 Loadings...................              107,185,411                                               =========================    BAT/NSPS Option 3--Zero Discharge.........    Discharge of SBF..........................                        0    Discharge of WBF and cuttings.............              100,387,607    Discharge of OBF..........................                        0                                               -------------------------      Total NSPS 3 Loadings...................              100,387,607                                               =========================Incremental Technology Option Loadings (Reductions):    BAT/NSPS Option 1: Discharge with 4.03%                  (2,604,704)     retention of SBF on cuttings.............    BAT/NSPS Option 2: Discharge with 3.82%                  (3,123,322)     retention of SBF on cuttings.............    BAT/NSPS Option 3: Zero Discharge of SBF-                (9,921,126)     wastes via land disposal or onsite     injection................................------------------------------------------------------------------------Note: EPA estimates the following GOM WBF/OBF/SBF new sources: Baseline--  38/2/20; BAT/NSPS Option 1 & 2--35/1/24; and BAT/NSPS Option 3--42/15/  3. EPA estimates no new sources for Offshore California or Cook Inlet,  AK.Note: The following terms are used in this table: long-term average  (LTA) and retention on cuttings (ROC).VII. Economic Impacts of Final Regulation    EPA evaluated the economic effects of the options considered fortoday's regulation. The methodology and results are presented in detailin the SBF Economic Analysis (EPA-821-B-00-012). The followingdiscussion presents a summary of that analysis and its conclusions.Small business impacts are summarized below and in Section IX.B.Environmental justice issues are summarized in Section IV.C.A. Impacts Analysis    EPA examined the potential impacts of the rule several ways:effects on drilling well costs, changes to financial performance ofdrilling facilities and production, impacts on small firms, andsecondary impacts. The economic methodology used to examine potentialimpacts on drilling well costs, firms, and secondary impacts is thesame as that used for the February 1999 proposal (see 64 FR 5521-5527;February 1999 proposal Economic Analysis (EPA-821-B-98-020)).    In response to comments and new data, EPA developed a series ofeconomic models for existing and new deep water projects in the Gulf ofMexico similar to those used for the Offshore and Coastal rules (see 58FR 12454-12512 and 61 FR 66086-66130). This additional analysis isdiscussed in the April 2000 NODA (65 FR 21558). The models focus on thedeep water Gulf because it is the region with the highest level ofcurrent drilling with and future interest in drilling with SBFs. Theeconomic models are based on a cash flow approach. Revenues are basedon an assumed price of oil, current and projected production of oil andgas, well production decline rates, and royalty rates. Operating costsare based on an assumed cost per BOE produced. The models are based ondata from MMS and industry (see Summary of Data to be Used In EconomicModeling for more details on the methodology, data, and parameters onwhich the models are based and how the models were constructed (DocketNo. W-98-26, Section III.G of the Rulemaking Record)) and SBF EconomicAnalysis, Appendix A. EPA received no comments on this NODA withrespect to the economic methodology or the data.    The costs and revenues are compared yearly and the project isassumed to run for 30 years or to shut in when operating costs exceedrevenues. That is, the economic models have differing lifetimesaccording to project characteristics and each model may have ashortened lifetime as a result of incremental costs. The model thencalculates the lifetime of the project, total production, and the netpresent value of the operation (net income of the operation over thelife of the project in terms of today's dollars), which includes thenet operating earnings, taxes, expenditures on drilling, other capitalexpenditures, etc. A positive net present value means that the projectis a good investment. In these cases, the return is greater than thediscount rate,[[Page 6884]]which represents the opportunity cost of capital. If the net presentvalue is negative, it means that money would have been better investedelsewhere. For existing projects, the model uses current operations;all expenditures in prior years, such as exploration, delineation, andinfrastructure development costs are considered sunk costs and are notaddressed. For new projects, the model uses data and parameters abouttiming of the various phases of exploration, delineation anddevelopment, along with cost estimates about costs incurred duringthese phases to compute a full lifetime financial model of theseprojects.    Each model is run twice--with and without the change due topollution control. The models support changes in both directions--i.e.,costs or savings. If a model shows the net present value of a projectto be positive in the baseline, but would have a negative net presentvalue under any of the regulatory options, some or all of the wellswould not be drilled. This difference between baseline andpostcompliance would generate production impacts.    The likely outcome of today's rule is an overall savings associatedwith the ability to discharge SBF cuttings (see Section VI.A). The costmodel (which provides the input to the economic models) projects thatthe savings exceed any incremental costs of compliance in theaggregate. EPA does not expect the alternate higher ROC limitation andstandard for drilling fluids with the stock base fluid performance ofesters to affect costs. EPA expects that operators will likely useester-based SBFs for the increased flexibility and not for any economicbenefits. The results of the economic models indicate no adverseimpacts on drilling well costs (exploratory or developmental), projectlifetime, or production for both BAT and NSPS projects. There are noadverse impacts on firms, employment, trade, or inflation.B. Small Business Analysis    Although today's rule will not have a significant economic impacton a substantial number of small entities (see Section VII.A), EPAassessed the impacts of the rule on small businesses. The smallbusiness analysis is described more fully in Chapter 6 of the SBFEconomic Analysis.    The small business definitions and the methodology were outlined inthe April 2000 NODA and the February 1999 Proposal Economic Analysisand have not changed. Briefly, EPA relied on the Small BusinessAdministration's size standards to determine whether a firm is a smallbusiness. If EPA could not find employment or revenue data to confirm afirm's size, it was classified as ``potentially'' small. EPA identified40 small and potentially small firms. As noted in the previousparagraph, today's rule results in cost savings, and EPA projects noadverse impacts on small businesses.VIII. Water Quality and Non-Water Quality Environmental Impacts ofFinal RegulationA. Overview of Water Quality and Non-Water Quality EnvironmentalImpacts    EPA conducted various analyses to assess the impact of the finalregulation on water quality, sediment quality, and human health. Ingeneral, EPA has found that no adverse impacts are expected fromcontrolled discharges of SBFs.B. Water Quality Modeling    In order to assess the impacts of potential SBF discharges to thereceiving waters, EPA conducted pore water, water column, and sedimentguidelines analyses. EPA calculated pollutant concentrations for boththe water column and pore water and compared them to the respective EPArecommended marine water quality criteria or to applicable statestandards to determine the nature and magnitude of any projected waterquality exceedances. Details of the analyses and results are presentedin the final SBF Environmental Assessment.    EPA included the discharge of WBFs in the engineering analyses (seeSection II.A). Environmental impacts such as water column, pore water,fish tissue and human health risk analyses were not estimated for thedischarge of WBFs versus the use and discharge of SBF cuttings.However, industry has provided information that drilling issignificantly more efficient using SBFs rather than WBFs because holevolumes with SBFs are approximately 1.8 times smaller. Therefore, thepollutant loadings of appropriately controlled SBF discharge are lessthan pollutant loadings associated with controlled WBF discharge.1. Water Column Water Quality Analyses    There are no water quality criteria exceedances in the water columnfor any of the regulatory options being considered including the ROCoption based on data from all four cuttings dryer technologies fordrilling fluids with the sediment toxicity and biodegradationcharacteristics of ester-based SBFs which results in a slightly higherLTA. Also, no Alaska state water quality standards are exceeded underthe discharge options in Cook Inlet, Alaska.2. Pore Water Quality Analyses    As described above in Section III.D.1, the addition of severalseabed survey data changed the estimated SBF sediment concentration at100 meters (328 feet) as used in the pore water quality analyses. Therevised analyses estimate that baseline (or BPT) pore water pollutantconcentrations at 100 meters from the discharge exceed recommendedwater quality criteria for the heavy metal, chromium, for two modelwell types, shallow water exploratory and deep water exploratory. Thereare no pore water exceedances of any of the Alaska state water qualitystandards for potential Cook Inlet, Alaska discharges. Also, there areno pore water exceedances under the controlled SBF discharges (i.e.,BAT/NSPS Options 1 and 2) including the ROC option based on data fromall four cuttings dryer technologies for drilling fluids with thesediment toxicity and biodegradation characteristics of ester-basedSBFs which results in a slightly higher LTA.3. Sediment Guidelines Analyses    The EPA proposed sediment guidelines for the protection of benthicorganisms assesses potential benthic impacts of certain metals. Therevised analyses, based on revised pore water concentrations, result in2 exceedances only under the baseline (or BPT) conditions. There are nosediment guidelines exceedances under controlled SBF dischargeconditions (i.e., BAT/NSPS Options 1 and 2) including the ROC optionbased on data from all four cuttings dryer technologies for drillingfluids with the sediment toxicity and biodegradation characteristics ofester-based SBFs which results in a slightly higher LTA.C. Human Health Effects Modeling    The human health risk analyses were revised to incorporate changesto the fish consumption rates (see Section III.D.b). The revisedanalyses show no risk to human health.D. Seabed Surveys    EPA reviewed the seabed surveys submitted during public comment tothe April 2000 NODA. As previously stated, EPA used data from twosurveys drilling six wells with SBFs in the environmental assessmentanalyses. Additionally, EPA also received information on the on-goingjoint Industry/MMS GOM seabed survey. The Industry/MMS workgroup has[[Page 6885]]completed the first two cruises of the four cruise study (see SectionIII.D.1). Outside of a 50-100' radius from the drilling facility, novisible cuttings accumulations (large or small) were detected at any ofthe drilling facility survey sites.E. Energy Impacts    As described in Sections III.E and IV.E, EPA included additionaldata and revised several parameters in estimating energy impacts of thefinal SBF rule. EPA estimated the amount of fuel required, expressed asbarrels of oil equivalents per year (BOE/yr), to operate the equipmentassociated with each of the regulatory options as well as the fuelconsumed by daily rig operations. EPA also estimated the current energyrequirements of WBF discharge in order to determine the relativedecrease in impacts of SBF versus WBF use. EPA does not expect thealternate higher ROC limitation and standard for drilling fluids withthe stock base fluid performance of esters to affect energy impactsbecause equipment used under the ester option (e.g., shale shakers,cuttings dryer, fines removal unit) has the same or similar energyrequirements. The results of the energy impact analysis are presentedin Tables 6 and 7 for existing and new sources, respectively.                      Table 6.--Incremental Summary Annual Energy Impacts, Existing Sources----------------------------------------------------------------------------------------------------------------                                                          Energy impacts: Reductions (Increases)a fuel use (BOE/                                                                                    yr)                    Technology basis                     -------------------------------------------------------                                                             Gulf of      Offshore     Cook Inlet,                                                             Mexico      California        AK           Total----------------------------------------------------------------------------------------------------------------BAT/NSPS Option 1: Discharge with LTA of 4.03% SBF ROC..      202,146             0            19       202,165BAT/NSPS Option 2: Discharge with LTA of 3.82% SBF ROC..      195,124             0             0       195,124BAT/NSPS Option 3: Zero Discharge of SBF-wastes via land     (346,459)       (6,138)       (6,067)     (358,664) disposal or onsite injection...........................----------------------------------------------------------------------------------------------------------------a Annual fuel usage reductions or increases are incremental to baseline/current practice (i.e., discharge of SBF-  cuttings at 10.2% ROC in the GOM and zero discharge in Offshore California and Cook Inlet, AK). Note: BOE = Barrels of Oil Equivalent.Note: The following terms are used in this table: long-term average (LTA) and retention on cuttings (ROC).    Table 7.--Incremental Summary Annual Energy Impacts, New Sources------------------------------------------------------------------------                                                     Energy impacts:               Technology basis                  Reductions (increases)a                                                    fuel use (BOE/yr)------------------------------------------------------------------------BAT/NSPS Option 1: Discharge with LTA of 4.03%                     6330 SBF ROC......................................BAT/NSPS Option 2: Discharge with LTA of 3.82%                     5693 SBF ROC......................................BAT/NSPS Option 3: Zero Discharge of SBF-                       (18,067) wastes via land disposal or onsite injection.------------------------------------------------------------------------a Annual fuel usage reductions or increases are incremental to baseline/  current practice (i.e., discharge of SBF-currings at 10.2% ROC in the  GOM). Note: BOE = Barrels of Oil Equivalent.Note: The following terms are used in this table: long-term average  (LTA) and retention on cuttings (ROC).Note: EPA estimates no new sources for Offshore California or Cook  Inlet, AK.F. Air Emission Impacts    EPA calculated the air emissions, expressed as short tons per year,resulting from activities associated with each of the regulatoryoptions. Air emissions are a function of the: (1) Type of fuel burned(e.g., natural gas or diesel); and (2) amount of fuel consumed asdetermined from the length of equipment operation and the fuelconsumption rate. The methodology and modeling parameters parallel thatof the energy impact analysis as the amount of fuel consumed is thebasis for the air emissions analysis. Therefore, the air emissionsanalysis includes the estimate of emissions of daily rig operations andan estimate of WBF drilling operation air emissions. EPA does notexpect the alternate higher ROC limitation and standard for drillingfluids with the stock base fluid performance of esters to affect airemissions because equipment used under the ester option (e.g., shaleshakers, cuttings dryer, fines removal unit) has the same or similarair emissions. The results of the air emission analysis are presentedin Tables 8 and 9 for existing and new sources, respectively.                      Table 8.--Incremental Summary Annual Air Emissions, Existing Sources----------------------------------------------------------------------------------------------------------------                                                          Annual Air Emission Reductions (Increases) a (tons/yr)                                                         -------------------------------------------------------                    Technology basis                         Gulf of      Offshore     Cook Inlet,                                                             Mexico      California        AK           Total----------------------------------------------------------------------------------------------------------------BAT/NSPS Option 1: Discharge with LTA of 4.03% SBF ROC..        3,172             0             0         3,172BAT/NSPS Option 2: Discharge with LTA of 3.82% SBF ROC..        3,074             0            (1)        3,073BAT/NSPS Option 3: Zero Discharge of SBF-wastes via land       (5,414)          (94)          (94)       (5,602) disposal or onsite injection...........................----------------------------------------------------------------------------------------------------------------a Annual air emissions reductions or increases are incremental to baseline/current practice (i.e., discharge of  SBF-cuttings at 10.2% ROC in the GOM and zero discharge in Offshore California and Cook Inlet, AK). Note: 1 ton = 2000 lbs.Note: The following terms are used in this table: long-term average (LTA) and retention cuttings (ROC).[[Page 6886]]Table 9.--Incremental Summary Air Emissions, New Sources--Gulf of Mexico------------------------------------------------------------------------                                                             Annual air                                                              emissions                     Technology basis                         reduction                                                             (increases)                                                             a (tons/yr)------------------------------------------------------------------------BAT/NSPS Option 1: Discharge with LTA of 4.03% SBF ROC....         (136)BAT/NSPS Option 2: Discharge with LTA of 3.82% SBF ROC....         (145)BAT/NSPS Option 3: Zero Discharge of SBF-wastes via land          (528) disposal or onsite injection.............................------------------------------------------------------------------------a Annual air emissions reductions or increases are incremental to  baseline/current practice (i.e., discharge of SBF-cuttings at 10.2%  ROC in the GOM). Note: 1 ton = 2000 lbs.Note: The following terms are used in this table: long-term average  (LTA) and retention on cuttings (ROC).Note: EPA estimates no new sources for Offshore California or Cook  Inlet, AK.G. Air Emissions Monetized Human Health Benefits    EPA estimated emissions associated with each of the regulatoryoptions as part of the NWQI analyses. The pollutants considered in theNWQI analyses are nitrogen oxides ( NOX), volatile organiccarbon (VOC), particulate matter (PM), sulfur dioxide (SO2),and carbon monoxide (CO). Of these pollutants, EPA monetized the humanhealth benefits or impacts associated with VOC, PM, and SO2emissions using the methodology presented in the EnvironmentalAssessment of the Final Effluent Limitations Guidelines and Standardsfor the Pharmaceutical Manufacturing Industry (EPA-821-B-98-008). Eachof these pollutants have human health impacts and reducing theseemissions can reduce these impacts.    Several VOCs exhibit carcinogenic and systemic effects and VOCs, ingeneral, are precursors to ground-level ozone, which negatively affectshuman health and the environment. PM impacts include aggravation ofrespiratory and cardiovascular disease and altered respiratory tractdefense mechanisms. SO2 impacts include nasal irritation andbreathing difficulties in humans and acid deposition in aquatic andterrestrial ecosystems.    The unit values (in 1990 dollars) are $489 to $2,212 per megagram(Mg) of VOC; $10,823 per Mg of PM; and $3,516 to $4,194 per Mg ofSO2. Using the Engineering News Record Construction CostIndex (see www.enr.com/cost/costcci.asp) these conversion factors arescaled up using the ratio of 6060:4732 (1999$:1990$). EPA does notexpect the alternate higher ROC limitation and standard for drillingfluids with the stock base fluid performance of esters to affectmonetized benefits because equipment used under the ester option (e.g.,shale shakers, cuttings dryer, fines removal unit) has the same orsimilar air emissions. Following is a summary of the monetized benefitsfor each of the regulatory options for both existing and new sources.BILLING CODE 6560-50-U[[Page 6887]][GRAPHIC] [TIFF OMITTED] TR22JA01.159[[Page 6888]][GRAPHIC] [TIFF OMITTED] TR22JA01.160H. Solid Waste Impacts    EPA calculated the amount of waste cuttings that would be landdisposed, injected onshore, and/or injected onsite in each regulatoryscenario, and determined that there would be a considerable reductionin the amount of drill cuttings land disposed and injected with theimplementation of a controlled discharge option for SBF-cuttings.    EPA's analyses show that under the SBF-cuttings zero dischargeoption as compared to current practice, for U.S. Offshore watersexisting sources, there would be an annual increase of 35 millionpounds of cuttings shipped to shore for disposal in non-hazardousoilfield waste (NOW) sites and an increase of 166 million pounds ofcuttings injected. In addition, under the SBF-cuttings zero dischargeoption, operators would use the more toxic OBFs. The zero dischargeoption for SBF-cuttings would lead to an increase in annual fuel usageof 358,664 BOE and an increase in annual air emissions of 5,602 tons.Finally, the SBF-cuttings zero discharge option in the U.S. Offshorewaters would lead to an increase of 51 million pounds of WBF cuttingsbeing discharged to U.S. Offshore waters. This pollutant loadingincrease is a result of GOM operators switching from efficient SBFdrilling to less efficient WBF drilling.    Additionally, EPA's analyses show that under the SBF-cuttings zerodischarge option as compared to current practice, for GOM new sources,there would be an annual increase of 3.4 million pounds of drillcuttings shipped to shore for disposal in NOW sites and an increase of10.2 million pounds of drill cuttings injected. These zero dischargeoptions for SBF-cuttings would lead to an increase in annual fuel useof 18,067 BOE and an increase in annual air emissions of 528 tons.Finally, the SBF-cuttings zero discharge option in the GOM would leadto an increase of 7.5 million pounds of WBF-cuttings being dischargedto U.S. Offshore waters. Again, this pollutant loading increase is aresult of GOM operators switching from efficient SBF drilling to lessefficient WBF drilling.I. Other Factors    EPA also considered the impact of the effluent limitationsguidelines and[[Page 6889]]standards on safety. EPA has identified two safety issues related todrilling fluids: (1) Deleterious vapors generated by organic materialsin drilling fluids; and (2) waste hauling activities that increase therisk of injury to workers.1. Vapors Generated by Organic Materials in Drilling Fluids    One of the key concerns in exploration and production projects isthe exposure of wellsite personnel to vapors generated by organicmaterials in drilling fluids (Docket No. W-98-26, Record No. III.D.12).Areas on the drilling location with the highest exposure potentials aresites near solids control and open pits. These areas are often enclosedin rooms and ventilated to prevent unhealthy levels of vapors fromaccumulating. If the total volume of organic vapors can be reduced thenany potential health effects will also be reduced regardless of thenature of the vapors.    Generally speaking the aromatic fraction of the vapors is the mosttoxic to the mammalian system. The high volatility and absorbabilitythrough the lungs combined with their high lipid solubility serve toincrease their toxicity. OBFs have a high aromatic content and vaporsgenerated from using these drilling fluids include aromatics (e.g.,alkybenzenes, naphthalenes, and alkyl-naphthalenes), alkanes (e.g., C7 -C 18 straight chained and branched), andalkenes. Some minerals oils also generate vapors that contain the sametypes of chemical compounds, but generally at lower concentrations, asthose found in the diesel vapors (e.g., aromatics, alkanes, cyclicalkanes, and alkenes). Because SBF are manufactured from compounds withspecifically defined compositions, the subsequent compound can excludetoxic aromatics. Consequently, toxic aromatics can be excluded from thevapors generated by using SBFs.    In general, SBFs (e.g., esters, LAOs, PAOs, IOs) generate muchlower concentrations of vapors than do OBFs (Docket No. W-98-26, RecordNo. III.D.12). Moreover, the vapors generated by these SBFs are lesstoxic than traditional OBFs because they do not contain aromatics.2. Waste Hauling Activities    Industry has commented in previous effluent guidelines, such as theCoastal Subcategory Oil and Gas Extraction and Development ELG, that azero discharge requirement would increase the risk of injury to workersdue to increased waste hauling activities. These activities includevessel trips to and from the drilling facility to haul waste, transferof waste from the drilling facility onto a service vessel, and transferin port onto a barge or dock.    EPA has identified and reviewed additional data sources todetermine the likelihood that imposition of a zero discharge limitationon cuttings contaminated with SBF could increase risk of injury due toadditional waste hauling demands. The sources of safety data are theU.S. Coast Guard (USCG), the Minerals Management Service (MMS), theAmerican Petroleum Institute (API), and the Offshore Marine ServiceAssociation (OMSA). The following is a summary of the findings fromthis review.    The data indicate that there are reported incidents that areassociated with the collection, hauling, and onshore disposal of wastesfrom offshore. However, the data do not distinguish whether any ofthese incidents can be attributed to specific waste managementactivities.    Most offshore incidents are due to human error or equipmentfailure. The rate at which these incidents occur will not be changedsignificantly by increased waste management activities. However, if thenumber of man hours and/or equipment hours are increased, there will bemore reportable incidents given an unchanged incident rate. Thesepotential increases may be offset by reduced incident rates throughincreased training or equipment maintenance and inspection; but thesechanges cannot be predicted. One indication that training andmaintenance can reduce incident rates is a 1998 API report entitled``1997 Summary of U.S. Occupational Injuries, Illnesses, and Fatalitiesin the Petroleum Industry,'' which established that injury incidentrates have been decreasing over the last 14 years. If this decreasecontinues, there should be no increase in the number of safetyincidents due to a requirement to haul SBF-contaminated cuttings toshore for disposal. The details of this analysis are available in atechnical support document in the rule record for today's final rule.IX. Regulatory RequirementsA. Executive Order 12866: Regulatory Planning and Review    Under Executive Order 12866 (58 FR 51735 (October 4, 1993)), theAgency must determine whether the regulatory action is ``significant''and therefore subject to OMB review and the requirements of theExecutive Order. The Order defines ``significant regulatory action'' asone that is likely to result in a rule that may:    (1) Have an annual effect on the economy of $100 million or more oradversely affect in a material way the economy, a sector of theeconomy, productivity, competition, jobs, the environment, publichealth or safety, or State, local, or tribal governments orcommunities;    (2) Create a serious inconsistency or otherwise interfere with anaction taken or planned by another agency;    (3) Materially alter the budgetary impact of entitlements, grants,user fees, or loan programs or the rights and obligations of recipientsthereof; or    (4) Raise novel legal or policy issues arising out of legalmandates, the President's priorities, or the principles set forth inthe Executive Order.    Pursuant to the terms of Executive Order 12866, it has beendetermined that this rule is a ``significant regulatory action.'' Assuch, this action was submitted to OMB for review. Changes made inresponse to OMB suggestions or recommendations are documented in thepublic record.B. Regulatory Flexibility Act (RFA), as amended by the Small BusinessRegulatory Enforcement Fairness Act of 1996 (SBREFA), 5 USC 601 et.seq.    The RFA generally requires an agency to prepare a regulatoryflexibility analysis of any rule subject to notice and comment rulerequirements under the Administrative Procedure Act or any otherstatute unless the agency certifies that the rule will not have asignificant economic impact on a substantial number of small entities.Small entities include small businesses, small organizations, and smallgovernmental jurisdictions.    For purposes of assessing the impacts of today's rule on smallentities, small entity is defined as: (1) A small business with fewerthan 500 employees for oil and gas production operators and less than$5 million per year in revenues for oil and gas services providers(i.e., the definitions from SBA's size standards); (2) a smallgovernmental jurisdiction that is a government of a city, county, town,school district, or special district with a population of less than50,000; and (3) a small organization that is any not-for-profitenterprise which is independently owned and operated and is notdominant in its field. After considering the economic impact of today'sfinal rule on small entities, I certify that this action will not havea significant economic impact on a substantial number of smallentities. Today's rule affects small businesses only; there are noimpacts on small governmental jurisdictions or small organizations.[[Page 6890]]    In determining whether a rule has a significant economic impact ona substantial number of small entities, the impact of concern is anysignificant adverse economic impact on small entities. Since theprimary purpose of the regulatory flexibility analysis is to identifyand address regulatory alternatives ``which minimizes any significanteconomic impact of the proposed rule on small entities.'' 5 U.S.C.Sections 603 and 604. Thus, an agency may certify that a rule will nothave a significant economic impact on a substantial number of smallentities if the rule relieves regulatory burden, or otherwise has apositive economic effect on all of the small entities subject to therule.    EPA projects that today's rule will result in operational savingsand will have no adverse economic impacts. These conclusions apply toall firms, both large and small. EPA estimates that between five and 40small businesses (between five and 40% of all firms) are covered bytoday's rule. If the small businesses are using SBF and continue to doso, or if they switch to SBF, they need to comply with today's effluentlimitations. EPA estimates that the operational savings associated withan allowable SBF-cuttings discharge will result in an economicadvantage, contrasted to other SBF-cuttings regulatory scenarios. EPAselected the controlled discharge option which will allow operators touse of SBF in place of OBF and WBFs. Using SBFs in place of OBFs willgenerally shorten the length of the drilling project and eliminate theneed to barge to shore or re-inject OBF-waste cuttings, therebyreducing costs and NWQI such as fuel use, air emissions, and landdisposal of OBFs. Use of SBFs in place of WBFs would also lead to: (1)a decrease in costs and NWQIs due to the decreased length of thedrilling project; and (2) a per well decrease of pollutants dischargeddue to improved technical performance of SBFs. EPA estimates that therule will result in annual savings of $48.9 million and no adverseeconomic impacts to the industry as a whole. Further, afterconsiderable study, EPA's record indicates that there will be nosignificant economic impacts to any small entity subject to the rule.The SBF Economic Analysis describes these results in more detail. Wehave therefore conducted that today's final rule will relieveregulatory burden for all small entities.C. Submission to Congress and the General Accounting Office    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by theSmall Business Regulatory Enforcement Fairness Act of 1996, generallyprovides that before a rule may take effect, the agency promulgatingthe rule must submit a rule report, which includes a copy of the rule,to each House of the Congress and to the Comptroller General of theUnited States. EPA will submit a report containing this rule and otherrequired information to the U.S. Senate, the U.S. House ofRepresentatives, and the Comptroller General of the United States priorto publication of the rule in the Federal Register. A major rule cannottake effect until 60 days after it is published in the FederalRegister. This action is not a ``major rule'' as defined by 5 U.S.C.804(2). This rule will be effective February 21, 2001.D. Paperwork Reduction Act    The Office of Management and Budget (OMB) has approved theinformation collection requirements contained in this rule under theprovisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. andhas assigned OMB control number 2040-0230.    The information collection requirements are related to the optionaluse of Best Management Practices (BMPs) in order to reduce SBF-cuttingsmonitoring. Operators that elect to not use the BMP alternative are notsubject to the information collection requirements in today's finalrule. BMPs are inherently pollution prevention practices. BMPs mayinclude the universe of pollution prevention encompassing productionmodifications, operational changes, material substitution, materialsand water conservation, and other such measures. BMPs include methodsto prevent toxic and hazardous pollutants from reaching receivingwaters. Because BMPs are most effective when organized into acomprehensive facility BMP Plan, EPA is requiring operators to completea BMP Plan when they select the BMP alternative.    The BMP alternative requires operators to develop and, whenappropriate, amend plans specifying how operators will implement thespecified BMP alternative, and to certify to the permitting authoritythat they have done so in accordance with good engineering practicesand the requirements of the regulation. The purpose of those provisionsis, respectively, to facilitate the implementation of BMP alternativeon a site-specific basis and to help the regulating authorities toensure compliance without requiring the submission of actual BMP Plans.Finally, the recordkeeping provisions are intended to facilitatetraining, to signal the need for different or more vigorouslyimplemented BMPs, and to facilitate compliance assessment.    The information collection requirements in the final rule include,for example: (1) Training personnel; (2) analyzing spills that occur;(3) identifying equipment items that might need to be maintained,upgraded, or repaired; (4) identifying procedures for wasteminimization; (5) performing monitoring (including the operation ofmonitoring systems) to establish equivalence with a numeric cuttingsretention limitation and to detect leaks, spills, and intentionaldiversion; and (6) generally to periodically evaluate the effectivenessof the BMP alternatives.    EPA does not expect that any confidential business information ortrade secrets will be required from oil and gas extraction operators aspart of this ICR. If information submitted in conjunction with this ICRwere to contain confidential business information, the respondent hasthe authority to request that the information be treated asconfidential business information. All data so designated will behandled by EPA pursuant to 40 CFR part 2. This information will bemaintained according to procedures outlined in EPA's Security ManualPart III, Chapter 9, dated August 9, 1976. Pursuant to section 308(b)of the CWA, effluent data may not be treated as confidential.    EPA estimated the burden and costs to the regulated community(approximately 67 SBF well drilling facilities annually) and EPA, theNPDES permit control authority, for data collection and record keepingassociated with implementation of the BMP alternative. EPA estimatesthe public reporting burden for the selected BMP option as 787 hoursper respondent per year (i.e., (16,750 initial hours/3 years + 47,168annual hours/year)/67 SBF well operators). EPA also estimated theannual burden for EPA Regions, the NPDES permit controllingauthorities, to review BMPs and ensure compliance. EPA estimates thatessentially all of the SBF discharges will occur in Federal offshorewaters or in Cook Inlet, Alaska, where EPA Region X retains NPDESpermit controlling authority. The EPA Regional burden for reviewing BMPPlans is estimated at 380 hours per year (i.e., (536 initial hours/3years + 201 annual hours/year)).    EPA estimates the public reporting costs as $24,058 per respondentper year (i.e., ($1,235,313 initial costs/3 years + $1,200,138 annualcosts/year)/67 SBF well operators). The EPA Regional costs forreviewing BMP Plans is estimated at approximately $12,149 per year(i.e.,[[Page 6891]]($17,152 initial costs/3 years + $6,432 annual costs/year)).    Burden means the total time, effort, or financial resourcesexpended by persons to generate, maintain, retain, or disclose orprovide information to or for a Federal agency. This includes the timeneeded to review instructions; develop, acquire, install, and utilizetechnology and systems for the purposes of collecting, validating, andverifying information, processing and maintaining information, anddisclosing and providing information; adjust the existing ways tocomply with any previously applicable instructions and requirements;train personnel to be able to respond to a collection of information;search data sources; complete and review the collection of information;and transmit or otherwise disclose the information.    An Agency may not conduct or sponsor, and a person is not requiredto respond to a collection of information unless it displays acurrently valid OMB control number. The OMB control numbers for EPA'sregulations are listed in 40 CFR part 9 and 48 CFR chapter 15. EPA isamending the table in 40 CFR part 9 of currently approved ICR controlnumbers issued by OMB for various regulations to list the informationrequirements contained in this final rule.E. Unfunded Mandates Reform Act    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), PublicLaw 104-4, establishes requirements for Federal agencies to assess theeffects of their regulatory actions on State, local, and tribalgovernments and the private sector. Under section 202 of the UMRA, EPAgenerally must prepare a written statement, including a cost-benefitanalysis, for proposed and final rules with ``Federal mandates'' thatmay result in expenditures to State, local, and tribal governments, inthe aggregate, or to the private sector, of $100 million or more in anyone year. Before promulgating an EPA rule for which a written statementis needed, section 205 of the UMRA generally requires EPA to identifyand consider a reasonable number of regulatory alternatives and adoptthe least costly, most cost-effective or least burdensome alternativethat achieves the objectives of the rule. The provisions of section 205do not apply when they are inconsistent with applicable law. Moreover,section 205 allows EPA to adopt an alternative other than the leastcostly, most cost-effective or least burdensome alternative if theAdministrator publishes with the final rule an explanation why thatalternative was not adopted. Before EPA establishes any regulatoryrequirements that may significantly or uniquely affect smallgovernments, including tribal governments, it must have developed undersection 203 of the UMRA a small government agency plan. The plan mustprovide for notifying potentially affected small governments, enablingofficials of affected small governments to have meaningful and timelyinput in the development of EPA regulatory proposals with significantFederal intergovernmental mandates, and informing, educating, andadvising small governments on compliance with the regulatoryrequirements.    EPA has determined that this rule does not contain a Federalmandate that may result in expenditures of $100 million or more forState, local, and tribal governments, in the aggregate, or the privatesector in any one year. EPA projects that the effect of the rule willbe a operational savings. EPA has estimated this savings at $48.9million (1999$, post-tax). Thus, today's rule is not subject to therequirements of Sections 202 and 205 of the UMRA.    EPA has determined that this rule contains no regulatoryrequirements that might significantly or uniquely affect smallgovernments. EPA projects that no small governments will be affected bythis rule as small governments are not engaged in oil and gasextraction operations in offshore and coastal waters or in issuingNPDES permits for oil and gas extraction operations in offshore andcoastal waters. Thus, today's rule is not subject to the requirementsof section 203 of the UMRA.F. Executive Order 13084: Consultation and Coordination With IndianTribal Governments    Under Executive Order 13084 EPA may not issue a regulation that isnot required by statute, that significantly or uniquely affects thecommunities of Indian Tribal governments, and that imposes substantialdirect compliance costs on those communities, unless the Federalgovernment provides the funds necessary to pay the direct compliancecosts incurred by the tribal governments, or EPA consults with thosegovernments. If EPA complies by consulting, Executive Order 13084requires EPA to provide to the Office of Management and Budget, in aseparately identified section of the preamble to the rule, adescription of the extent of EPA's prior consultation withrepresentatives of affected tribal governments, a summary of the natureof their concerns, and a statement supporting the need to issue theregulation. In addition, Executive Order 13084 requires EPA to developan effective process permitting elected officials and otherrepresentatives of Indian tribal governments ``to provide meaningfuland timely input in the development of regulatory policies on mattersthat significantly or uniquely affect their communities.''    Today's rule does not significantly or uniquely affect thecommunities of Indian tribal governments nor does it impose substantialdirect compliance costs on them. EPA has determined that currently, nocommunities of Indian tribal governments are affected by this rule asIndian tribal governments are not engaged in oil and gas extractionoperations in offshore and coastal waters or in issuing NPDES permitsfor oil and gas extraction operations in offshore and coastal waters.Accordingly, the requirements of section 3(b) of Executive Order 13084do not apply to this rule.G. Executive Order 13132: Federalism    Executive Order 13132, entitled ``Federalism'' (64 FR 43255, August10, 1999), requires EPA to develop an accountable process to ensure``meaningful and timely input by State and local officials in thedevelopment of regulatory policies that have federalism implications.''``Policies that have federalism implications'' is defined in theExecutive Order to include regulations that have ``substantial directeffects on the States, on the relationship between the nationalgovernment and the States, or on the distribution of power andresponsibilities among the various levels of government.''    This final rule does not have federalism implications. It will nothave substantial direct effects on the States, on the relationshipbetween the national government and the States, or on the distributionof power and responsibilities among the various levels of government,as specified in Executive Order 13132. The rule establishes effluentlimitations and standards imposing requirements that apply to oil andgas extraction operations in offshore and coastal waters. EPA hasdetermined that there are no oil and gas extraction operations inoffshore and coastal waters that are owned and operated by State orlocal governments. Therefore, this rule will not impose anyrequirements on State or local governments. Further, the rule will notaffect State governments' authority to implement CWA and UIC permittingprograms. In fact, the final rule may reduce administrative costs onStates that have authorized NPDES programs because although theseStates must incorporate the new limitations and[[Page 6892]]standards in new and revised NPDES permits, they no longer will need tomake Best Professional Judgement (BPJ) determinations regarding theappropriate level of technology control. We recognize that there may bea small administrative cost to the State of Alaska to assist EPA Region10 in determining whether Coastal Cook Inlet, Alaska, operators qualifyfor the SBF-cuttings zero discharge exemption (see Section V.F). Thus,Executive Order 13132 does not apply to this rule.H. National Technology Transfer and Advancement Act    As noted in the proposed rule (64 FR 5528), section 12(d) of theNational Technology Transfer and Advancement Act (NTTAA) of 1995, PubL. 104-113 section 12(d) (15 U.S.C. 272 note), directs EPA to usevoluntary consensus standards in its regulatory activities unless to doso would be inconsistent with applicable law or otherwise impractical.Voluntary consensus standards are technical standards (e.g., materialsspecifications, test methods, sampling procedures, and businesspractices) that are developed or adopted by voluntary consensusstandard bodies. The NTTAA directs EPA to provide Congress, through theOffice of Management and Budget (OMB), explanations when the Agencydecides not to use available and applicable voluntary consensusstandards.    This rule involves technical standards. The rule requiresdischargers to measure for two metals, PAH content (as phenanthrene),sediment toxicity, aqueous toxicity, biodegradation rate, formation oilcontent, and base fluid retained on cuttings. EPA performed a search toidentify potentially applicable voluntary consensus standards thatcould be used to measure the parameters in today's rule. EPA did locateseveral voluntary consensus standards that required modification forinclusion in the final rule. EPA considered public comments on theproposed rule and worked with stakeholders, including the industrysponsored Synthetic Based Muds Research Consortium (SBMRC), to modifyor develop new standards for various parameters (i.e., sedimenttoxicity, biodegradation rate, PAH content (as phenanthrene), formationoil content, base fluid retained on cuttings). EPA has decided to usemodified versions of the following voluntary consensus standards: (1)EPA Method 1654A; (2) ASTM E-1367-92; (3) ISO 11734:1995; and (4) APIRecommended Practice 13B-2. As indicated by industry comments on theFebruary 1999 proposal and April 2000 NODA, industry stakeholderssupport the use of these modified voluntary consensus standards (seeDocket No. W-98-26, Record No. IV.A.a.13).I. Executive Order 13045: Protection of Children From EnvironmentalHealth Risks and Safety Risks    The Executive Order 13045, ``Protection of Children fromEnvironmental Health Risks and Safety Risks'' (62 FR 19885, April 23,1997), applies to any rule that: (1) Is determined to be ``economicallysignificant'' as defined under Executive Order 12866, and (2) concernsan environmental health or safety risk that EPA has reason to believemay have a disproportionate effect on children. If the regulatoryaction meets both criteria, the Agency must evaluate the environmentalhealth or safety effects of the planned rule on children and explainwhy the planned regulation is preferable to other potentially effectiveand reasonably feasible alternatives considered by the Agency. Thisfinal rule is not subject to E.O. 13045 because it is not``economically significant'' as defined under Executive Order 12866,and because the rule does not concern an environmental health or safetyrisk that may have a disproportionate effect on children.J. Executive Order 13158: Marine Protected Areas    Executive Order 13158 (65 FR 34909, May 31, 2000) requires EPA to``expeditiously propose new science-based regulations, as necessary, toensure appropriate levels of protection for the marine environment.''EPA may take action to enhance or expand protection of existing marineprotected areas and to establish or recommend, as appropriate, newmarine protected areas. The purpose of the executive order is toprotect the significant natural and cultural resources within themarine environment, which means ``those areas of coastal and oceanwaters, the Great Lakes and their connecting waters, and submergedlands thereunder, over which the United States exercises jurisdiction,consistent with international law.''    EPA believes that this final rule is consistent with the objectivesof the Executive Order to protect the ocean environment. By encouragingthe use of appropriately controlled SBFs in the place of more toxicOBFs, the ocean will be protected from the effects of spills of OBFsand from the effects of disposal of OBFs onshore. By encouraging theuse of appropriately controlled SBFs over WBFs, there will much lessdrilling waste generated and discharged to the ocean per well and thedrilling waste discharged will be far less toxic and will biodegrade ata much faster rate than those of traditional drilling fluids.X. Regulatory Implementation    Upon promulgation of these regulations, the effluent limitationsfor the appropriate subcategory must be applied in all Federal andState NPDES permits issued to affected direct dischargers in the oiland gas extraction industry. This section discusses the relationship ofupset and bypass provisions, variances and modifications, andmonitoring requirements.A. Implementation of Limitations and Standards    Upon the promulgation of these regulations, all new and reissuedFederal and State NPDES permits issued to direct dischargers in the oiland gas extraction industry must include the effluent limitations forthe appropriate subcategory. Permit writers should be aware that EPAhas now finalized revisions to 40 CFR 122.44(a) which could beparticularly relevant to the development of NPDES permits for the oiland gas extraction point source category (see 65 FR 30989, May 15,2000). As finalized, the revision would require that permits havelimitations for all applicable guidelines-listed pollutants but allowsfor the waiver of sampling requirements for guideline-listed pollutantson a case-by-case basis if the discharger can certify that thepollutant is not present in the discharge or present in only backgroundlevels from intake water with no increase due to the activities of thedischargers. New sources and new dischargers are not eligible for thiswaiver for their first permit term, and monitoring can be re-established through a minor modification if the discharger expands orchanges its process. Further, the permittee must notify the permitwriter of any modifications that have taken place over the course ofthe permit term and, if necessary, monitoring can be reestablishedthrough a minor modification.B. Upset and Bypass Provisions    A ``bypass'' is an intentional diversion of waste streams from anyportion of a treatment facility. An ``upset'' is an exceptionalincident in which there is unintentional and temporary noncompliancewith technology-based permit effluent limitations because of factorsbeyond the reasonable control of the permittee. EPA's regulationsconcerning bypasses and upsets are set forth at 40 CFR 122.41(m) and(n), and 40 CFR 403.16 (upset) and 403.17[[Page 6893]](bypass). The reader is also referred to the Offshore Guidelines (58 FR12501) for a discussion on upset and bypass provisions.C. Variances and Modifications    The CWA requires application of the effluent limitations andstandards established pursuant to section 301, 304, 306, or thepretreatment standards of section 307 to all direct and indirectdischargers. However, section 301(n) provides for the modification ofthese national requirements in a limited number of circumstances.Moreover, the Agency has established administrative mechanisms toprovide an opportunity for relief from the application of nationaleffluent limitations guidelines and pretreatment standards forcategories of existing sources for priority, conventional and non-conventional pollutants (e.g., fundamentally different factorvariances, removal credits).    The Fundamentally Different Factors (FDF) variances considers thosefacility specific factors which a permittee may consider to be uniquelydifferent from those considered in the formulation of an effluentlimitations guidelines as to make the limitation inapplicable. An FDFvariance must be based only on information submitted to EPA during therulemaking establishing the effluent limitations guidelines from whichthe variance is being requested, or on information the applicant didnot have a reasonable opportunity to submit during the rulemakingprocess for these effluent limitations guidelines. FDF variancerequests must be received by the permitting authority within 180 daysof publication of the final rule. The specific regulations covering therequirements for the administration of FDF variances are found at 40CFR 122.21(m)(1), and 40 CFR part 125, subpart D.D. Relationship of Effluent Limitations to NPDES Permits and MonitoringRequirements    Effluent limitations act as a primary mechanism to control thedischarges of pollutants to waters of the United States. Theselimitations are applied to individual facilities through NPDES permitsissued by EPA or authorized States under section 402 of the Act.    The Agency has developed the limitations for this regulation tocover the discharge of pollutants for this industrial category. Inspecific cases, the NPDES permitting authority may elect to establishtechnology-based permit limits for pollutants not covered by thisregulation. In addition, if State water quality standards or otherprovisions of State or Federal Law require limits on pollutants notcovered by this regulation (or require more stringent limits on coveredpollutants), the permitting authority must apply those limitations.    Working in conjunction with the effluent limitations are themonitoring conditions set out in a NPDES permit. An integral part ofthe monitoring conditions is the point at which a facility must monitorto demonstrate compliance. The point at which a sample is collected canhave a dramatic effect on the monitoring results for that facility.Therefore, it may be necessary to require internal monitoring points inorder to ensure compliance. Authority to address internal waste streamsis provided in 40 CFR 122.44(i)(1)(iii) and 122.45(h). Permit writersmay establish additional internal monitoring points to the extentconsistent with EPA's regulations.    An important component of the monitoring requirements establishedby the permitting authority is the frequency at which monitoring isrequired. In costing the various technology options for the oil and gasextraction industry, EPA assumed yearly SBF stock limitationsmonitoring for mercury, cadmium, PAH (as phenanthrene), sedimenttoxicity, and biodegradation rates and daily or monthly monitoring fordiesel oil contamination, formation oil contamination, base fluidretained on cuttings, aqueous toxicity, and sediment toxicity. Thesemonitoring frequencies may be lower than those generally imposed bysome permitting authorities, but EPA believes these reduced frequenciesare appropriate due to the relative costs of monitoring when comparedto the estimated costs of complying with the promulgated limitations.E. Analytical Methods    Section 304(h) of the Clean Water Act directs EPA to promulgateguidelines establishing test procedures for the analysis of pollutants.These test procedures (methods) are used to determine the presence andconcentration of pollutants in wastewater, and are used for compliancemonitoring and for filing applications for the NPDES program under 40CFR 122.21, 122.41, 122.44 and 123.25, and for the implementation ofthe pretreatment standards under 40 CFR 403.10 and 403.12. To date, EPAhas promulgated methods for conventional pollutants, toxic pollutants,and for some non-conventional pollutants. The five conventionalpollutants are defined at 40 CFR 401.16. Table I-B at 40 CFR part 136lists the analytical methods approved for these pollutants. The 65toxic metals and organic pollutants and classes of pollutants aredefined at 40 CFR 401.15. From the list of 65 classes of toxicpollutants EPA identified a list of 126 ``Priority Pollutants.'' Thislist of Priority Pollutants is shown, for example, at 40 CFR part 423,Appendix A. The list includes non-pesticide organic pollutants, metalpollutants, cyanide, asbestos, and pesticide pollutants.    Currently approved methods for metals and cyanide are included inthe table of approved inorganic test procedures at 40 CFR 136.3, TableI-B. Table I-C at 40 CFR 136.3 lists approved methods for measurementof non-pesticide organic pollutants, and Table I-D lists approvedmethods for the toxic pesticide pollutants and for other pesticidepollutants. Dischargers must use the test methods promulgated at 40 CFR136.3 or incorporated by reference in the tables, when available, tomonitor pollutant discharges from the oil and gas industry, unlessspecified otherwise in part 435 or by the permitting authority.    As part this rule, EPA is promulgating the use of analyticalmethods for determining additional parameters that are specific tocharacterizing SBFs and other drilling fluids which do not disperse inwater. These additional stock base fluid parameters include PAH content(as phenanthrene), sediment toxicity, and biodegradation rate.Additional discharge limitations include prohibition of diesel oildischarge, formation (crude) oil contamination, aqueous phase toxicity,sediment toxicity, and quantity of drilling fluid discharged withcuttings.    EPA worked with stakeholders to identify methods for determiningthese parameters. For PAH content (as phenanthrene), EPA ispromulgating the use of EPA Method 1654A. For biodegradation rate, EPAis promulgating the use of the anaerobic closed bottle biodegradationtest (i.e., ISO 11734:1995) as modified for the marine environment(i.e., Appendix 4 of subpart A of 40 CFR part 435). For base fluidsediment toxicity, EPA is promulgating the use of the American Societyfor Testing and Material (ASTM) Method E-1367-92 supplemented withsediment preparation procedures (i.e., Appendix 3 of subpart A of 40CFR part 435). For drilling fluid sediment toxicity, EPA ispromulgating the use of ASTM Method E-1367-92 supplemented withsediment preparation procedures (i.e., Appendix 3 of subpart A of 40CFR part 435) and reference drilling fluid preparation procedures(i.e., Appendix 8 of subpart[[Page 6894]]A of 40 CFR part 435). For aqueous toxicity, EPA is promulgating theuse of the Suspended Particulate Phase (SPP) toxicity test (Appendix 2of subpart A of 40 CFR part 435). For formation (crude) oilcontamination in drilling fluid, EPA is promulgating the use of twomethods: a reverse phase extraction fluorescence test (RPE) and a gaschromatography/mass spectrometry (GC/MS) test. The RPE test (i.e.,Appendix 6 of subpart A of 40 CFR part 435) is a screening method thatprovides a quick and inexpensive determination of oil contamination foruse on offshore well drilling sites, while the GC/MS test (i.e.,Appendix 5 of subpart A of 40 CFR part 435) provides: (1) A definitiveidentification and quantification of oil contamination for baselineanalysis; and (2) confirmatory results for the RPE when the RPE resultsneed confirmation. For determining the quantity of drilling fluiddischarged with cuttings, EPA is promulgating the use of the AmericanPetroleum Institute (API) Retort Method (Recommended Practice 13B-2)with sampling procedures (i.e., Appendix 7 of subpart A of 40 CFR part435). For determining when Coastal Cook Inlet, Alaska, operatorsqualify for an exemption from the Coastal requirement of zero dischargefor SBF-cuttings, EPA is promulgating the use of the procedure outlinedin Appendix 1 of subpart D of 40 CFR part 435.    EPA Method 1654A, ASTM E-1367-92, and ISO 11734:1995 areincorporated by reference into 40 CFR part 435 because they arepublished methods that are widely available to the public.Modifications to the anaerobic closed bottle biodegradation test (i.e.,ISO 11734:1995) are provided in Appendix 4 of subpart A of 40 part 435.The SPP toxicity test is given in Appendix 2 of subpart A of 40 part435. Supplemental sediment preparation procedures for ASTM E-1367-92are provided in Appendix 3 of subpart A of 40 CFR part 435. Referencedrilling fluid preparation procedures for ASTM E-1367-92 are providedin Appendix 8 of subpart A of 40 CFR part 435. The text of the GC/MStest, RPE test, and the API retort method are provided in Appendices 5-7 of subpart A of 40 CFR part 435. The procedure for determining whenCoastal Cook Inlet operators qualify for an exemption from the Coastalrequirement of zero discharge for SBF-cuttings is provided in Appendix1 of subpart D of 40 CFR part 435.Appendix A to the Preamble--Abbreviations, Acronyms, and OtherTerms Used in This PreambleAct--Clean Water ActAgency--U.S. Environmental Protection AgencyAOGCC--Alaska Oil and Gas Conservation CommissionAPI--American Petroleum InstituteANL--Argonne National Laboratory (DOE)ASTM--American Society of Testing and MaterialsBADCT--The best available demonstrated control technology, for newsources under section 306 of the Clean Water Act.BAT--The best available technology economically achievable, undersection 304(b)(2)(B) of the Clean Water Act.bbl--barrel, 42 U.S. gallonsBCT--Best conventional pollutant control technology under section304(b)(4)(B).BMP--Best management practices under section 304(e) of the CleanWater Act.BOD--Biochemical oxygen demand.BOE--Barrels of oil equivalentBPJ--Best Professional JudgementBPT--Best practicable control technology currently available, undersection 304(b)(1) of the Clean Water Act.CERCLA--Comprehensive Environmental Response, Compensation, andLiability ActCFR--U.S. Code of Federal RegulationsClean Water Act--Federal Water Pollution Control Act Amendments of1972 as amended (33 U.S.C. 1251 et seq)Conventional pollutants--Constituents of wastewater as determined bysection 304(a)(4) of the Act, including, but no limited to,pollutants classified as biochemical oxygen demanding, suspendedsolids, oil and grease, fecal coliform, and pHDirect discharger--A facility which discharges or may dischargepollutants to waters of the United StatesD&B--Dun & BradstreetDOE--U.S. Department of EnergyDWD--Deep-water development model wellDWE--Deep-water exploratory model wellEMO--Enhanced Mineral Oil Drilling FluidEPA--U.S. Environmental Protection AgencyFR--Federal RegisterGC--Gas ChromatographyGC/FID--Gas Chromatography with Flame Ionization DetectionGC/MS--Gas Chromatography with Mass Spectroscopy DetectionGOM--Gulf of MexicoIndirect discharger--A facility that introduces wastewater into apublicly owned treatment works.IRFA--Initial Regulatory Flexibility AnalysisLC50 (or LC50)--The concentration of a test material thatis lethal to 50% of the test organisms in a bioassaymg/l--milligrams per literMMS--U.S. Department of Interior, Minerals Management ServiceNAF--Non-Aqueous Drilling Fluid (includes OBFs, EMOs, and SBFs)Non-conventional pollutants--Pollutants that have not beendesignated as either conventional pollutants or priority pollutantsNODA--Notice of Data Availability (65 FR 21548; April 21, 2000)NOIA--National Ocean Industries AssociationNOW--Nonhazardous Oilfield WasteNPDES--National Pollutant Discharge Elimination SystemNRDC--Natural Resources Defense Council, Inc.NSPS--New source performance standards under section 306 of theClean Water ActNTTAA--National Technology Transfer and Advancement ActNWQI--Non-Water Quality Environmental ImpactsOBF--Oil-Based Drilling FluidOCS--Outer Continental ShelfOMB--Office of Management and BudgetPAH--Polynuclear Aromatic HydrocarbonPDC--Polycrystalline Diamond Compact (drill bit)POTW--Publicly Owned Treatment Works ppm--parts per millionPPA--Pollution Prevention Act of 1990Priority pollutants--The 65 pollutants and classes of pollutantsdeclared toxic under section 307(a) of the Clean Water ActPSES--Pretreatment standards for existing sources of indirectdischarges, under section 307(b) of the ActPSNS--Pretreatment standards for new sources of indirect discharges,under sections 307(b) and (c) of the ActRFA--Regulatory Flexibility ActROC--Retention on CuttingsRPE--Reverse Phase ExtractionSBA--U.S. Small Business AdministrationSBF--Synthetic Based Drilling FluidSBF Development Document--Development Document for Final EffluentLimitations Guidelines and Standards for Synthetic-Based DrillingFluids and other Non-Aqueous Drilling Fluids in the Oil and GasExtraction Point Source Category (EPA-821-B-00-013)SBF Economic Analysis--Economic Analysis of Final EffluentLimitations Guidelines and Standards for Synthetic-Based DrillingFluids and other Non-Aqueous Drilling Fluids in the Oil and GasExtraction Point Source Category (EPA-821-B-00-012)SBF Environmental Assessment--Environmental Assessment of FinalEffluent Limitations Guidelines and Standards for Synthetic-BasedDrilling Fluids and other Non-Aqueous Drilling Fluids in the Oil andGas Extraction Point Source Category (EPA-821-B-00-014)SBF Statistical Support Document--Statistical Analyses SupportingFinal Effluent Limitations Guidelines and Standards for Synthetic-Based Drilling Fluids and other Non-Aqueous Drilling Fluids in theOil and Gas Extraction Point Source Category (EPA-821-B-00-015)SBMRC--Synthetic Based Muds Research ConsortiumSBREFA--Small Business Regulatory Enforcement Fairness ActSIC--Standard Industrial ClassificationSPP--Suspended Particulate Phase toxicity test (Appendix 2 toSubpart A of 40 CFR 435)[[Page 6895]]SWD--Shallow-water development model wellSWE--Shallow-water exploratory model wellTSS--Total Suspended SolidsUMRA--Unfunded Mandates Reform ActUIC--Underground Injection Control programs of the Safe DrinkingWater Act of 1974 as amendedU.S.C.--United States CodeWBF--Water-Based Drilling FluidList of Subjects40 CFR Part 9    Reporting and recordkeeping requirements.40 CFR Part 435    Environmental protection, Non-aqueous drilling fluids, Oil and gasextraction, Pollution prevention, Synthetic based drilling fluids,Waste treatment and disposal, Water non-dispersible drilling fluids,Water pollution control.    Dated: December 28, 2000.Carol M. Browner,Administrator.    For the reasons set forth in this preamble, 40 CFR parts 9 and 435are amended as follows:PART 9--OMB APPROVALS UNDER THE PAPERWORK REDUCTION ACT    1. The authority citation for part 9 continues to read as follows:    Authority: 7 U.S.C. 135 et seq., 136-136y; 15 U.S.C. 2001, 2003,2005, 2006, 2601-2671; 21 U.S.C. 331j, 346a, 348; 31 U.S.C. 9701; 33U.S.C. 1251 et seq., 1311, 1313d, 1314, 1318, 1321, 1326, 1330,1342, 1344, 1345 (d) and (e), 1361; E.O. 11735, 38 FR 21243, 3 CFR,1971-1975 Comp. p. 973; 42 U.S.C. 241, 242b, 243, 246, 300f, 300g,300g-1, 300g-2, 300g-3, 300g-4, 300g-5, 300g-6, 300j-1, 300j-2,300j-3, 300j-4, 300j-9, 1857 et seq., 6901-6992k, 7401-7671q, 7542,9601-9657, 11023, 11048.    2. In Sec. 9.1 the table is amended by adding entries in numericalorder under a new heading titled ``Oil and Gas Extraction Point SourceCategory'' to read as follows:Sec. 9.1  OMB approvals under the Paperwork Reduction Act.* * * * *------------------------------------------------------------------------                                                             OMB control                      40 CFR citation                            No.------------------------------------------------------------------------                  *        *        *        *        *Oil and Gas Extraction Point Source Category:    435.13.................................................    2040-0230    435.15.................................................    2040-0230    435.43.................................................    2040-0230    435.45.................................................    2040-0230                  *        *        *        *        *------------------------------------------------------------------------PART 435--OIL AND GAS EXTRACTION POINT SOURCE CATEGORY    1. The authority citation for Part 435 is revised to read asfollows:    Authority: 33 U.S.C. 1311, 1314, 1316, 1317, 1318, 1342 and1361.Subpart A--Offshore Subcategory    2. Section 435.11 is amended by revising paragraphs (b) through(cc) and by adding paragraphs (dd) through (tt) to read as follows:Sec. 435.11  Special definitions.* * * * *    (b) Average of daily values for 30 consecutive days means theaverage of the daily values obtained during any 30 consecutive dayperiod.    (c) Base fluid means the continuous phase or suspending medium of adrilling fluid formulation.    (d) Base fluid retained on cuttings as applied to BAT effluentlimitations and NSPS refers to the American Petroleum InstituteRecommended Practice 13B-2 supplemented with the specifications,sampling methods, and averaging method for retention values provided inAppendix 7 of Subpart A of this part.    (e) Biodegradation rate as applied to BAT effluent limitations andNSPS for drilling fluids and drill cuttings refers to the ISO11734:1995 method: ``Water quality--Evaluation of the `ultimate'anaerobic biodegradability of organic compounds in digested sludge--Method by measurement of the biogas production (1995 edition)''supplemented with modifications in Appendix 4 of 40 CFR part 435,subpart A. This incorporation by reference was approved by the Directorof the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFRpart 51. Copies may be obtained from the American National StandardsInstitute, 11 West 42nd Street, 13th Floor, New York, NY 10036. Copiesmay be inspected at the Office of the Federal Register, 800 NorthCapitol Street, NW., Suite 700, Washington, DC. A copy may also beinspected at EPA's Water Docket, 401 M Street SW., Washington, DC20460.    (f) Daily values as applied to produced water effluent limitationsand NSPS means the daily measurements used to assess compliance withthe maximum for any one day.    (g) Deck drainage means any waste resulting from deck washings,spillage, rainwater, and runoff from gutters and drains including drippans and work areas within facilities subject to this Subpart.    (h) Development facility means any fixed or mobile structuresubject to this subpart that is engaged in the drilling of productivewells.    (i) Diesel oil refers to the grade of distillate fuel oil, asspecified in the American Society for Testing and Materials StandardSpecification for Diesel Fuel Oils D975-91, that is typically used asthe continuous phase in conventional oil-based drilling fluids. Thisincorporation by reference was approved by the Director of the FederalRegister in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copiesmay be obtained from the American Society for Testing and Materials,100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies may beinspected at the Office of the Federal Register, 800 North CapitolStreet, NW., Suite 700, Washington, DC. A copy may also be inspected atEPA's Water Docket, 401 M Street SW., Washington, DC 20460.    (j) Domestic waste means materials discharged from sinks, showers,laundries, safety showers, eye-wash stations, hand-wash stations, fishcleaning stations, and galleys located within facilities subject tothis Subpart.    (k) Drill cuttings means the particles generated by drilling intosubsurface geologic formations and carried out from the wellbore withthe drilling fluid. Examples of drill cuttings include small pieces ofrock varying in size and texture from fine silt to gravel. Drillcuttings are generally generated from solids control equipment andsettle out and accumulate in quiescent areas in the solids controlequipment or other equipment processing drilling fluid (i.e.,accumulated solids).    (1) Wet drill cuttings means the unaltered drill cuttings andadhering drilling fluid and formation oil carried out from the wellborewith the drilling fluid.    (2) Dry drill cuttings means the residue remaining in the retortvessel after completing the retort procedure specified in appendix 7 ofsubpart A of this part.    (l) Drilling fluid means the circulating fluid (mud) used in therotary drilling of wells to clean and condition the hole and tocounterbalance formation pressure. Classes of drilling fluids are:    (1) Water-based drilling fluid means the continuous phase andsuspending[[Page 6896]]medium for solids is a water-miscible fluid, regardless of the presenceof oil.    (2) Non-aqueous drilling fluid means the continuous phase andsuspending medium for solids is a water-immiscible fluid, such asoleaginous materials (e.g., mineral oil, enhanced mineral oil,paraffinic oil, C16-C18 internal olefins, andC8-C16 fatty acid/2-ethylhexyl esters).    (i) Oil-based means the continuous phase of the drilling fluidconsists of diesel oil, mineral oil, or some other oil, but contains nosynthetic material or enhanced mineral oil.    (ii) Enhanced mineral oil-based means the continuous phase of thedrilling fluid is enhanced mineral oil.    (iii) Synthetic-based means the continuous phase of the drillingfluid is a synthetic material or a combination of synthetic materials.    (m) Enhanced mineral oil as applied to enhanced mineral oil-baseddrilling fluid means a petroleum distillate which has been highlypurified and is distinguished from diesel oil and conventional mineraloil in having a lower polycyclic aromatic hydrocarbon (PAH) content.Typically, conventional mineral oils have a PAH content on the order of0.35 weight percent expressed as phenanthrene, whereas enhanced mineraloils typically have a PAH content of 0.001 or lower weight percent PAHexpressed as phenanthrene.    (n) Exploratory facility means any fixed or mobile structuresubject to this Subpart that is engaged in the drilling of wells todetermine the nature of potential hydrocarbon reservoirs.    (o) Formation oil means the oil from a producing formation which isdetected in the drilling fluid, as determined by the GC/MS complianceassurance method specified in appendix 5 of subpart A of this part whenthe drilling fluid is analyzed before being shipped offshore, and asdetermined by the RPE method specified in appendix 6 of subpart A ofthis part when the drilling fluid is analyzed at the offshore point ofdischarge. Detection of formation oil by the RPE method may beconfirmed by the GC/MS compliance assurance method, and the results ofthe GC/MS compliance assurance method shall supercede those of the RPEmethod.    (p) M9IM means those offshore facilities continuously manned bynine (9) or fewer persons or only intermittently manned by any numberof persons.    (q) M10 means those offshore facilities continuously manned by ten(10) or more persons.    (r) Maximum as applied to BAT effluent limitations and NSPS fordrilling fluids and drill cuttings means the maximum concentrationallowed as measured in any single sample of the barite fordetermination of cadmium and mercury content.    (s) Maximum for any one day as applied to BPT, BCT and BAT effluentlimitations and NSPS for oil and grease in produced water means themaximum concentration allowed as measured by the average of four grabsamples collected over a 24-hour period that are analyzed separately.Alternatively, for BAT and NSPS the maximum concentration allowed maybe determined on the basis of physical composition of the four grabsamples prior to a single analysis.    (t) Maximum weighted mass ratio averaged over all NAF well sectionsfor BAT effluent limitations and NSPS for base fluid retained oncuttings means the weighted average base fluid retention for all NAFwell sections as determined by the API Recommended Practice 13B-2,using the methods and averaging calculations presented in Appendix 7 ofsubpart A of this part.    (u) Method 1654A refers to Method 1654, Revision A, entitled ``PAHContent of Oil by HPLC/UV,'' December 1992, which is published inMethods for the Determination of Diesel, Mineral, and Crude Oils inOffshore Oil and Gas Industry Discharges, EPA-821-R-92-008. Thisincorporation by reference was approved by the Director of the FederalRegister in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copiesmay be obtained from the National Technical Information Service,Springfield, VA 22161, 703-605-6000. Copies may be inspected at theOffice of the Federal Register, 800 North Capitol Street, NW., Suite700, Washington, DC. A copy may also be inspected at EPA's WaterDocket, 401 M Street SW., Washington, DC 20460.    (v) Minimum as applied to BAT effluent limitations and NSPS fordrilling fluids and drill cuttings means the minimum 96-hourLC50 value allowed as measured in any single sample of thedischarged waste stream. Minimum as applied to BPT and BCT effluentlimitations and NSPS for sanitary wastes means the minimumconcentration value allowed as measured in any single sample of thedischarged waste stream.    (w)(1) New source means any facility or activity of thissubcategory that meets the definition of ``new source'' under 40 CFR122.2 and meets the criteria for determination of new sources under 40CFR 122.29(b) applied consistently with all of the followingdefinitions:    (i) Water area as used in ``site'' in 40 CFR 122.29 and 122.2 meansthe water area and water body floor beneath any exploratory,development, or production facility where such facility is conductingits exploratory, development or production activities.    (ii) Significant site preparation work as used in 40 CFR 122.29means the process of surveying, clearing or preparing an area of thewater body floor for the purpose of constructing or placing adevelopment or production facility on or over the site.    (2) ``New Source'' does not include facilities covered by anexisting NPDES permit immediately prior to the effective date of theseguidelines pending EPA issuance of a new source NPDES permit.    (x) No discharge of free oil means that waste streams may not bedischarged that contain free oil as evidenced by the monitoring methodspecified for that particular stream, e.g., deck drainage ormiscellaneous discharges cannot be discharged when they would cause afilm or sheen upon or discoloration of the surface of the receivingwater; drilling fluids or cuttings may not be discharged when they failthe static sheen test defined in Appendix 1 of subpart A of this part.    (y) Parameters that are regulated in this Subpart and listed withapproved methods of analysis in Table 1B at 40 CFR 136.3 are defined asfollows:    (1) Cadmium means total cadmium.    (2) Chlorine means total residual chlorine.    (3) Mercury means total mercury.    (4) Oil and Grease means total recoverable oil and grease.    (z) PAH (as phenanthrene) means polynuclear aromatic hydrocarbonsreported as phenanthrene.    (aa) Produced sand means the slurried particles used in hydraulicfracturing, the accumulated formation sands and scales particlesgenerated during production. Produced sand also includes desanderdischarge from the produced water waste stream, and blowdown of thewater phase from the produced water treating system.    (bb) Produced water means the water (brine) brought up from thehydrocarbon-bearing strata during the extraction of oil and gas, andcan include formation water, injection water, and any chemicals addeddownhole or during the oil/water separation process.    (cc) Production facility means any fixed or mobile structuresubject to this Subpart that is either engaged in well completion orused for active recovery of hydrocarbons from producing formations.    (dd) Sanitary waste means the human body waste discharged fromtoilets and[[Page 6897]]urinals located within facilities subject to this Subpart.    (ee) Sediment toxicity as applied to BAT effluent limitations andNSPS for drilling fluids and drill cuttings refers to the ASTM E 1367-92 method: ``Standard Guide for Conducting 10-day Static SedimentToxicity Tests with Marine and Estuarine Amphipods,'' 1992, withLeptocheirus plumulosus as the test organism and sediment preparationprocedures specified in Appendix 3 of 40 CFR part 435, subpart A. Thisincorporation by reference was approved by the Director of the FederalRegister in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copiesmay be obtained from the American Society for Testing and Materials,100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies may beinspected at the Office of the Federal Register, 800 North CapitolStreet, NW., Suite 700, Washington, DC. A copy may also be inspected atEPA's Water Docket, 401 M Street SW., Washington, DC 20460.    (ff) Solids control equipment means shale shakers, centrifuges, mudcleaners, and other equipment used to separate drill cuttings and/orstock barite solids from drilling fluid recovered from the wellbore.    (gg) SPP toxicity as applied to BAT effluent limitations and NSPSfor drilling fluids and drill cuttings refers to the bioassay testprocedure presented in Appendix 2 of subpart A of this part.    (hh) Static sheen test means the standard test procedure that hasbeen developed for this industrial subcategory for the purpose ofdemonstrating compliance with the requirement of no discharge of freeoil. The methodology for performing the static sheen test is presentedin Appendix 1 of subpart A of this part.    (ii) Stock barite means the barite that was used to formulate adrilling fluid.    (jj) Stock base fluid means the base fluid that was used toformulate a drilling fluid.    (kk) Synthetic material as applied to synthetic-based drillingfluid means material produced by the reaction of specific purifiedchemical feedstock, as opposed to the traditional base fluids such asdiesel and mineral oil which are derived from crude oil solely throughphysical separation processes. Physical separation processes includefractionation and distillation and/or minor chemical reactions such ascracking and hydro processing. Since they are synthesized by thereaction of purified compounds, synthetic materials suitable for use indrilling fluids are typically free of polycyclic aromatic hydrocarbons(PAH's) but are sometimes found to contain levels of PAH up to 0.001weight percent PAH expressed as phenanthrene. Internal olefins andvegetable esters are two examples of synthetic materials suitable foruse by the oil and gas extraction industry in formulating drillingfluids. Internal olefins are synthesized from the isomerization ofpurified straight-chain (linear) hydrocarbons such as C16-C18 linear alpha olefins. C16-C18linear alpha olefins are unsaturated hydrocarbons with the carbon tocarbon double bond in the terminal position. Internal olefins aretypically formed from heating linear alpha olefins with a catalyst. Thefeed material for synthetic linear alpha olefins is typically purifiedethylene. Vegetable esters are synthesized from the acid-catalyzedesterification of vegetable fatty acids with various alcohols. EPAlisted these two branches of synthetic fluid base materials to provideexamples, and EPA does not mean to exclude other synthetic materialsthat are either in current use or may be used in the future. Asynthetic-based drilling fluid may include a combination of syntheticmaterials.    (ll) Well completion fluids means salt solutions, weighted brines,polymers, and various additives used to prevent damage to the well boreduring operations which prepare the drilled well for hydrocarbonproduction.    (mm) Well treatment fluids means any fluid used to restore orimprove productivity by chemically or physically altering hydrocarbon-bearing strata after a well has been drilled.    (nn) Workover fluids means salt solutions, weighted brines,polymers, or other specialty additives used in a producing well toallow for maintenance, repair or abandonment procedures.    (oo) 4-day LC50 as applied to the sediment toxicity BATeffluent limitations and NSPS means the concentration (milligrams/kilogram dry sediment) of the drilling fluid in sediment that is lethalto 50 percent of the Leptocheirus plumulosus test organisms exposed tothat concentration of the drilling fluids after four days of constantexposure.    (pp) 10-day LC50 as applied to the sediment toxicity BATeffluent limitations and NSPS means the concentration (milligrams/kilogram dry sediment) of the base fluid in sediment that is lethal to50 percent of the Leptocheirus plumulosus test organisms exposed tothat concentration of the base fluids after ten days of constantexposure.    (qq) 96-hour LC50 means the concentration (parts permillion) or percent of the suspended particulate phase (SPP) from asample that is lethal to 50 percent of the test organisms exposed tothat concentration of the SPP after 96 hours of constant exposure.    (rr) C16-C18 internal olefin means a 65/35blend, proportioned by mass, of hexadecene and octadecene,respectively. Hexadecene is an unsaturated hydrocarbon with a carbonchain length of 16, an internal double carbon bond, and is representedby the Chemical Abstracts Service (CAS) No. 26952-14-7. Octadecene isan unsaturated hydrocarbon with a carbon chain length of 18, aninternal double carbon bond, and is represented by the ChemicalAbstracts Service (CAS) No. 27070-58-2. (Properties available from theChemical Abstracts Service, 2540 Olentangy River Road, PO Box 3012,Columbus, OH, 43210).    (ss) C16-C18 internal olefin drilling fluidmeans a C16-C18 internal olefin drilling fluidformulated as specified in Appendix 8 of subpart A of this part.    (tt) C12-C14 ester and C8 estermeans the fatty acid/2-ethylhexyl esters with carbon chain lengthsranging from 8 to 16 and represented by the Chemical Abstracts Service(CAS) No. 135800-37-2. (Properties available from the ChemicalAbstracts Service, 2540 Olentangy River Road, PO Box 3012, Columbus,OH, 43210)    3. In Sec. 435.12 the table is amended by removing the entries``Drilling muds'' and ``Drill cuttings'' and by adding new entries(after ``Deck drainage'') for ``Water based'' and ``Non-aqueous'' toread as follows:Sec. 435.12  Effluent limitations guidelines representing the degree ofeffluent reduction attainable by the application of the bestpracticable control technology currently available (BPT).* * * * *[[Page 6898]]                                    BPT Effluent Limitations--Oil and Grease                                            [In milligrams per liter]----------------------------------------------------------------------------------------------------------------                                                                 Average of values for 30   Pollutant parameter waste source      Maximum for any 1 day    consecutive days shall     Residual chlorine                                                                        not exceed         minimum for any 1 day----------------------------------------------------------------------------------------------------------------*                  *                  *                  *                  *                  *                                                        *Water-based:    Drilling fluids..................  (\1\)...................  (\1\)...................  NA    Drill Cuttings...................  (\1\)...................  (\1\)...................  NANon-aqueous:    Drilling fluids..................  No discharge............  No discharge............  NA    Drill Cuttings...................  (\1\)...................  (\1\)...................  NA*                  *                  *                  *                  *                  *                                                       *----------------------------------------------------------------------------------------------------------------\1\ No discharge of free oil.* * * * *    4. In Sec. 435.13 the table is amended by revising entry (B) under``Drilling fluids and drill cuttings'' and by revising footnote 2 andadding footnotes 5-11 to read as follows:Sec. 435.13  Effluent limitations guidelines representing the degree ofeffluent reduction attainable by the application of the best availabletechnology economically achievable (BAT).* * * * *                        Bat Effluent Limitations------------------------------------------------------------------------                                    Pollutant           BAT effluent         Waste source               parameter            limitation------------------------------------------------------------------------*                  *                  *                  *                  *                  *                  *Drilling fluids and drill cuttings:*                  *                  *                  *                  *                  *                  *(B) For facilities located beyond 3 miles from shore:    Water-based drilling        SPP Toxicity.....  Minimum 96-hour LC50     fluids and associated                          of the SPP Toxicity     drill cuttings.                                Test \2\ shall be 3%                                                    by volume.                                Free oil.........  No discharge.\3\                                Diesel oil.......  No discharge.                                Mercury..........  1 mg/kg dry weight                                                    maximum in the stock                                                    barite.                                Cadmium..........  3 mg/kg dry weight                                                    maximum in the stock                                                    barite.    Non-aqueous drilling        .................  No discharge.     fluids (NAFs).Drill cuttings associated with non-aqueous drilling fluids:    Stock Limitations (C16-C18  Mercury..........  1 mg/kg dry weight     internal olefin).                              maximum in the stock                                                    barite.                                Cadmium..........  3 mg/kg dry weight                                                    maximum in the stock                                                    barite.                                Polynuclear        PAH mass ratio \5\                                 Aromatic           shall not exceed                                 Hydrocarbons       1x10-5.                                 (PAH).                                Sediment toxicity  Base fluid sediment                                                    toxicity ratio \6\                                                    shall not exceed                                                    1.0.                                Biodegradation     Biodegradation rate                                 rate.              ratio \7\ shall not                                                    exceed 1.0.    Discharge Limitations.....  Diesel oil.......  No discharge.                                SPP Toxicity.....  Minimum 96-hour LC50                                                    of the SPP Toxicity                                                    Test \2\ shall be 3%                                                    by volume.                                Sediment toxicity  Drilling fluid                                                    sediment toxicity                                                    ratio \8\ shall not                                                    exceed 1.0.                                Formation Oil....  No discharge.\9\                                Base fluid         For NAFs that meet                                 retained on        the stock                                 cuttings.          limitations (C16-C18                                                    internal olefin) in                                                    this table, the                                                    maximum weighted                                                    mass ratio averaged                                                    over all NAF well                                                    sections shall be                                                    6.9 g-NAF base fluid/                                                    100 g-wet drill                                                    cuttings.\10\                                                   For NAFs that meet                                                    the C12-C14 ester or                                                    C8 ester stock                                                    limitations in                                                    footnote 11 of this                                                    table, the maximum                                                    weighted mass ratio                                                    averaged over all                                                    NAF well sections                                                    shall be 9.4 g-NAF                                                    base fluid/100 g-wet                                                    drill cuttings.[[Page 6899]]*                  *                  *                  *                    *                  *              *------------------------------------------------------------------------*                  *                  *                  *     *                  *              *\2\ As determined by the suspended particulate phase (SPP) toxicity test  (Appendix 2 of subpart A of this part).\3\ As determined by the static sheen test (Appendix 1 of subpart A of  this part).*                  *                  *                  *     *                  *              *\5\ PAH mass ratio = Mass (g) of PAH (as phenanthrene)/Mass (g) of stock  base fluid as determined by EPA Method 1654, Revision A, (specified at  Sec.  435.11(u)) entitled ``PAH Content of Oil by HPLC/UV,'' December  1992, which is published in Methods for the Determination of Diesel,  Mineral, and Crude Oils in Offshore Oil and Gas Industry Discharges,  EPA-821-R-92-008. This incorporation by reference was approved by the  Director of the Federal Register in accordance with 5 U.S.C. 552(a)  and 1 CFR part 51. Copies may be obtained from the National Technical  Information Service, Springfield, VA 22161, 703-605-6000. Copies may  be inspected at the Office of the Federal Register, 800 North Capitol  Street, NW., Suite 700, Washington, DC. A copy may also be inspected  at EPA's Water Docket, 401 M Street SW., Washington, DC 20460.\6\ Base fluid sediment toxicity ratio = 10-day LC50 of C16-C18 internal  olefin/10-day LC50 of stock base fluid as determined by ASTM E 1367-92  [specified at Sec.  435.11(ee)] method: ``Standard Guide for  Conducting 10-day Static Sediment Toxicity Tests with Marine and  Estuarine Amphipods,'' 1992, after preparing the sediment according to  the method specified in Appendix 3 of subpart A of this part. This  incorporation by reference was approved by the Director of the Federal  Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies  may be obtained from the American Society for Testing and Materials,  100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies may be  inspected at the Office of the Federal Register, 800 North Capitol  Street, NW., Suite 700, Washington, DC. A copy may also be inspected  at EPA's Water Docket, 401 M Street SW., Washington, DC 20460.\7\ Biodegradation rate ratio = Cumulative gas production (ml) of C16-  C18 internal olefin/Cumulative gas production (ml) of stock base  fluid, both at 275 days as determined by ISO 11734:1995 [specified at  Sec.  435.11(e)] method: ``Water quality--Evaluation of the `ultimate'  anaerobic biodegradability of organic compounds in digested sludge--  Method by measurement of the biogas production (1995 edition)'' as  modified for the marine environment (Appendix 4 of subpart A of this  part). This incorporation by reference was approved by the Director of  the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part  51. Copies may be obtained from the American National Standards  Institute, 11 West 42nd Street, 13th Floor, New York, NY 10036. Copies  may be inspected at the Office of the Federal Register, 800 North  Capitol Street, NW., Suite 700, Washington, DC. A copy may also be  inspected at EPA's Water Docket, 401 M Street SW., Washington, DC  20460.\8\ Drilling fluid sediment toxicity ratio = 4-day LC50 of C16-C18  internal olefin drilling fluid/4-day LC50 of drilling fluid removed  from drill cuttings at the solids control equipment as determined by  ASTM E 1367-92 (specified at Sec.  435.11(ee)) method: ``Standard  Guide for Conducting 10-day Static Sediment Toxicity Tests with Marine  and Estuarine Amphipods,'' 1992, after preparing the sediment  according to the method specified in Appendix 3 of subpart A of this  part. This incorporation by reference was approved by the Director of  the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part  51. Copies may be obtained from the American Society for Testing and  Materials, 100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies  may be inspected at the Office of the Federal Register, 800 North  Capitol Street, NW., Suite 700, Washington, DC. A copy may also be  inspected at EPA's Water Docket, 401 M Street SW., Washington, DC  20460.\9\ As determined before drilling fluids are shipped offshore by the GC/  MS compliance assurance method (Appendix 5 of subpart A of this part),  and as determined prior to discharge by the RPE method (Appendix 6 of  subpart A of this part) applied to drilling fluid removed from drill  cuttings. If the operator wishes to confirm the results of the RPE  method (Appendix 6 of subpart A of this part), the operator may use  the GC/MS compliance assurance method (Appendix 5 of subpart A of this  part). Results from the GC/MS compliance assurance method (Appendix 5  of subpart A of this part) shall supercede the results of the RPE  method (Appendix 6 of subpart A of this part).\10\ Maximum permissible retention of non-aqueous drilling fluid (NAF)  base fluid on wet drill cuttings averaged over drilling intervals  using NAFs as determined by the API retort method (Appendix 7 of  subpart A of this part). This limitation is applicable for NAF base  fluids that meet the base fluid sediment toxicity ratio (Footnote 6),  biodegradation rate ratio (Footnote 7), PAH, mercury, and cadmium  stock limitations (C16-C18 internal olefin) defined above in this  table.\11\ Maximum permissible retention of non-aqueous drilling fluid (NAF)  base fluid on wet drill cuttings average over drilling intervals using  NAFs as determined by the API retort method (Appendix 7 of subpart A  of this part). This limitation is applicable for NAF base fluids that  meet the ester base fluid sediment toxicity ratio and ester  biodegradation rate ratio stock limitations defined as: (a) ester base  fluid sediment toxicity ratio = 10-day LC50 of C12-C14 ester or C8  ester /10-day LC50 of stock base fluid as determined by ASTM E 1367-92  (specified at Sec.  435.11(ee)) method: ``Standard Guide for  Conducting 10-day Static Sediment Toxicity Tests with Marine and  Estuarine Amphipods,'' 1992, after preparing the sediment according to  the method specified in Appendix 3 of subpart A of this part. This  incorporation by reference was approved by the Director of the Federal  Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies  may be obtained from the American Society for Testing and Materials,  100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies may be  inspected at the Office of the Federal Register, 800 North Capitol  Street, NW., Suite 700, Washington, DC. A copy may also be inspected  at EPA's Water Docket, 401 M Street SW., Washington, DC 20460. (b)  ester biodegradation rate ratio = Cumulative gas production (ml) of  C12-C14 ester or C8 ester/Cumulative gas production (ml) of stock base  fluid, both at 275 days as determined by ISO 11734:1995 (specified at  Sec.  435.11(e)) method: ``Water quality--Evaluation of the `ultimate'  anaerobic biodegradability of organic compounds in digested sludge--  Method by measurement of the biogas production (1995 edition)'' as  modified for the marine environment (Appendix 4 of subpart A of this  part). This incorporation by reference was approved by the Director of  the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part  51. Copies may be obtained from the American National Standards  Institute, 11 West 42nd Street, 13th Floor, New York, NY 10036. Copies  may be inspected at the Office of the Federal Register, 800 North  Capitol Street, NW., Suite 700, Washington, DC. A copy may also be  inspected at EPA's Water Docket, 401 M Street SW., Washington, DC  20460. (c) PAH mass ratio (Footnote 5), mercury, and cadmium stock  limitations (C16-C18 internal olefin) defined above in this table.    5. In Sec. 435.14 the table is amended by revising entry (B) under``Drilling fluids and drill cuttings'' to read as follows:Sec. 435.14  Effluent limitations guidelines representing the degree ofeffluent reduction attainable by the application of the bestconventional pollutant control technology (BCT).* * * * *                        BCT Effluent Limitations------------------------------------------------------------------------                                  Pollutant         Waste source             parameter      BCT effluent limitation------------------------------------------------------------------------*                  *                  *                  *                  *                  *                  *Drilling fluids and drill cuttings:[[Page 6900]]*                  *                  *                  *                  *                  *                  *(B) For facilities located beyond 3 miles from shore:    Water-based drilling       Free Oil.......  No discharge.\2\     fluids and associated     drill cuttings.    Non-aqueous drilling       ...............  No discharge.     fluids.    Drill cuttings associated  Free Oil.......  No discharge.\2\     with non-aqueous     drilling fluids.------------------------------------------------------------------------*                  *                  *                  *     *                  *              *\2\ As determined by the static sheen test (Appendix 1 of Subpart A of  this part).*                  *                  *                  *     *                  *                  *    6. In Sec. 435.15 the table is amended by revising entry (B) under``Drilling fluids and drill cuttings'' and by revising footnote 2 andadding footnotes 5-11 to read as follows:Sec. 435.15  Standards of performance for new sources (NSPS).* * * * *                 New Source Performance Standards (NSPS)------------------------------------------------------------------------                                    Pollutant         Waste source               parameter               NSPS------------------------------------------------------------------------*                  *                  *                  *                  *                  *                  *Drilling fluids and drill cuttings:*                  *                  *                  *                  *                  *                  *(B) For facilities located beyond 3 miles from shore:    Water-based drilling        SPP Toxicity.....  Minimum 96-hour LC50     fluids and associated                          of the SPP Toxicity     drill cuttings.                                Test 2 shall be 3%                                                    by volume.                                Free oil.........  No discharge.3                                Diesel oil.......  No charge.                                Mercury..........  1mg/kg dry weight                                                    maximum in the stock                                                    barite.                                Cadmium..........  3 mg/kg dry weight                                                    maximum in the stock                                                    barite.    Non-aqueous drilling        .................  No charge.     fluids.Drill cuttings associated with non-aqueous drilling fluids:    Stock Limitations (C16-C18  Mercury..........  1mg/kg dry weight     internal olefin.                               maximum in the stock                                                    barite.                                Cadmium..........  3 mg/kg dry weight                                                    maximum in the stock                                                    barite.                                Polynuclear        PAH mass ratio5 shall                                 Aromatic           not exceed 1 x 10-5                                 Hydrocarbons                                 (PAH).                                Sediment toxicity  Base fluid sediment                                                    toxicity ratio 6                                                    shall not exceed                                                    1.0.                                Biodegradation     Biodegradation rate                                 rate.              ratio7 shall not                                                    exceed 1.0.    Discharge Limitations.....  Diesel oil.......  No discharge.                                SPP Toxicity.....  Minimum 96-hour LC50                                                    of the SPP Toxicity                                                    Test 2 shall be 3%                                                    by volume.                                Sediment toxicity  Drilling fluid                                                    sediment toxicity                                                    ratio 8 shall not                                                    exceed 1.0.                                Formation Oil....  No discharge.9                                Base fluid         For NAFs that meet                                 retained on        the stock                                 cuttings.          limitations (C16-C18                                                    internal olefin) in                                                    this table, the                                                    maximum weighted                                                    mass ratio averaged                                                    over all NAF well                                                    sections shall be                                                    6.9 g-NAF base fluid/                                                    100 g-wet drill                                                    cuttings.10                                                   For NAFs that meet                                                    the C12-C14 ester or                                                    C8 ester stock                                                    limitations in                                                    footnote 11 of this                                                    table, the maximum                                                    weighted mass ratio                                                    averaged over all                                                    NAF well sections                                                    shall be 9.4 g-NAF                                                    base fluid/100 g-wet                                                    drill cuttings.*                  *                  *                *                 *                  *                  *------------------------------------------------------------------------*                  *                  *                *   *                  *              *\2\ As determined by the suspended particulate phase (SPP) toxicity test  (Appendix 2 of subpart A of this part).\3\ As determined by the static sheen test (appendix 1 of subpart A of  this part).*                  *                  *                *   *                  *                *\5\ PAH mass ratio = Mass (g) of PAH (as phenanthrene)/Mass (g) of stock  base fluid as determined by EPA Method 1654, Revision A, (specified at  Sec.  435.11(u)) entitled ``PAH Content of Oil by HPLC/UV,'' December  1992, which is published in Methods for the Determination of Diesel,  Mineral, and Crude Oils in Offshore Oil and Gas Industry Discharges,  EPA-821-R-92-008. This incorporation by reference was approved by the  Director of the Federal Register in accordance with 5 U.S.C. 552(a)  and 1 CFR part 51. Copies may be obtained from the National Technical  Information Service, Springfield, VA 22161, 703-605-6000. Copies may  be inspected at the Office of the Federal Register, 800 North Capitol  Street, NW., Suite 700, Washington, DC. A copy may also be inspected  at EPA's Water Docket, 401 M Street SW., Washington, DC 20460.[[Page 6901]]\6\ Base fluid sediment toxicity ratio = 10-day LC50 of C16-C18 internal  olefin/10-day LC50 of stock base fluid as determined by ASTM E 1367-92  (specified at Sec.  435.11(ee)) method: ``Standard Guide for  Conducting 10-day Static Sediment Toxicity Tests with Marine and  Estuarine Amphipods,'' 1992, after preparing the sediment according to  the method specified in Appendix 3 of subpart A of this part. This  incorporation by reference was approved by the Director of the Federal  Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies  may be obtained from the American Society for Testing and Materials,  100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies may be  inspected at the Office of the Federal Register, 800 North Capitol  Street, NW., Suite 700, Washington, DC. A copy may also be inspected  at EPA's Water Docket, 401 M Street SW., Washington, DC 20460.\7\ Biodegradation rate ratio = Cumulative gas production (ml) of C16-  C18 internal olefin/Cumulative gas production (ml) of stock base  fluid, both at 275 days as determined by ISO 11734:1995 (specified at  Sec.  435.11(e)) method: ``Water quality--Evaluation of the `ultimate'  anaerobic biodegradability of organic compounds in digested sludge--  Method by measurement of the biogas production (1995 edition)'' as  modified for the marine environment (Appendix 4 of subpart A of this  part). This incorporation by reference was approved by the Director of  the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part  51. Copies may be obtained from the American National Standards  Institute, 11 West 42nd Street, 13th Floor, New York, NY 10036. Copies  may be inspected at the Office of the Federal Register, 800 North  Capitol Street, NW., Suite 700, Washington, DC. A copy may also be  inspected at EPA's Water Docket, 401 M Street SW., Washington, DC  20460.\8\ Drilling fluid sediment toxicity ratio = 4-day LC50 of C16-C18  internal olefin drilling fluid/4-day LC50 of drilling fluid removed  from drill cuttings at the solids control equipment as determined by  ASTM E 1367-92 (specified at Sec.  435.11(ee)) method: ``Standard  Guide for Conducting 10-day Static Sediment Toxicity Tests with Marine  and Estuarine Amphipods,'' 1992, after preparing the sediment  according to the method specified in Appendix 3 of subpart A of this  part. This incorporation by reference was approved by the Director of  the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part  51. Copies may be obtained from the American Society for Testing and  Materials, 100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies  may be inspected at the Office of the Federal Register, 800 North  Capitol Street, NW., Suite 700, Washington, DC. A copy may also be  inspected at EPA's Water Docket, 401 M Street SW., Washington, DC  20460.\9\ As determined before drilling fluids are shipped offshore by the GC/  MS compliance assurance method (Appendix 5 of subpart A of this part),  and as determined prior to discharge by the RPE method (Appendix 6 of  subpart A of this part) applied to drilling fluid removed from drill  cuttings. If the operator wishes to confirm the results of the RPE  method (Appendix 6 of subpart A of this part), the operator may use  the GC/MS compliance assurance method (Appendix 5 of subpart A of this  part). Results from the GC/MS compliance assurance method (Appendix 5  of subpart A of this part) shall supercede the results of the RPE  method (Appendix 6 of subpart A of this part).\10\ Maximum permissible retention of non-aqueous drilling fluid (NAF)  base fluid on wet drill cuttings averaged over drilling intervals  using NAFs as determined by the API retort method (Appendix 7 of  subpart A of this part). This limitation is applicable for NAF base  fluids that meet the base fluid sediment toxicity ratio (Footnote 6),  biodegradation rate ratio (Footnote 7), PAH, mercury, and cadmium  stock limitations (C16-C18 internal olefin) defined above in this  table.\11\ Maximum permissible retention of non-aqueous drilling fluid (NAF)  base fluid on wet drill cuttings average over drilling intervals using  NAFs as determined by the API retort method (Appendix 7 of subpart A  of this part). This limitation is applicable for NAF base fluids that  meet the ester base fluid sediment toxicity ratio and ester  biodegradation rate ratio stock limitations defined as: (a) Ester base  fluid sediment toxicity ratio = 10-day LC50 of C12-C14 ester or C8  ester /10-day LC50 of stock base fluid as determined by ASTM E 1367-92  [specified at Sec.  435.11(ee)] method: ``Standard Guide for  Conducting 10-day Static Sediment Toxicity Tests with Marine and  Estuarine Amphipods,'' 1992, after preparing the sediment according to  the method specified in Appendix 3 of subpart A of this part. This  incorporation by reference was approved by the Director of the Federal  Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies  may be obtained from the American Society for Testing and Materials,  100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies may be  inspected at the Office of the Federal Register, 800 North Capitol  Street, NW., Suite 700, Washington, DC. A copy may also be inspected  at EPA's Water Docket, 401 M Street SW., Washington, DC 20460; (b)  Ester biodegradation rate ratio = Cumulative gas production (ml) of  C12-C14 ester or C8 ester/Cumulative gas production (ml) of stock base  fluid, both at 275 days as determined by ISO 11734:1995 (specified at  Sec.  435.11(e)) method: ``Water quality--Evaluation of the `ultimate'  anaerobic biodegradability of organic compounds in digested sludge--  Method by measurement of the biogas production (1995 edition)'' as  modified for the marine environment (Appendix 4 of subpart A of this  part). This incorporation by reference was approved by the Director of  the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part  51. Copies may be obtained from the American National Standards  Institute, 11 West 42nd Street, 13th Floor, New York, NY 10036. Copies  may be inspected at the Office of the Federal Register, 800 North  Capitol Street, NW., Suite 700, Washington, DC. A copy may also be  inspected at EPA's Water Docket, 401 M Street SW., Washington, DC  20460; and (c) PAH mass ratio (Footnote 5), mercury, and cadmium stock  limitations (C16-C18 internal olefin) defined above in this table.    7. Subpart A of this part is amended by adding Appendices 3 through8 as follows:Appendix 3 to Subpart A of Part 435--Procedure for Mixing Base Fluidswith Sediments    This procedure describes a method for amending uncontaminatedand nontoxic (control) sediments with the base fluids that are usedto formulate synthetic-based drilling fluids and other non-aqueousdrilling fluids. Initially, control sediments shall be press-sievedthrough a 2000 micron mesh sieve to remove large debris. Then press-sieve the sediment through a 500 micron sieve to remove indigenousorganisms that may prey on the test species or otherwise confoundtest results. Homogenize control sediment to limit the effects ofsettling that may have occurred during storage. Sediments should behomogenized before density determinations and addition of base fluidto control sediment. Because base fluids are strongly hydrophobicand do not readily mix with sediment, care must be taken to ensurebase fluids are thoroughly homogenized within the sediment. Allconcentrations are weight-to-weight (mg of base fluid to kg of drycontrol sediment). Sediment and base fluid mixing shall beaccomplished by using the following method.    1. Determine the wet to dry ratio for the control sediment byweighing approximately 10 g subsamples of the screened andhomogenized wet sediment into tared aluminum weigh pans. Drysediment at 105  deg.C for 18-24 h. Remove sediment and cool in adesiccator until a constant weight is achieved. Re-weigh the samplesto determine the dry weight. Determine the wet/dry ratio by dividingthe net wet weight by the net dry weight:[Wet Sediment Weight (g)]/[Dry Sediment Weight (g)] = Wet to DryRatio  [1]    2. Determine the density (g/mL) of the wet control or dilutionsediment. This shall be used to determine total volume of wetsediment needed for the various test treatments.[Mean Wet Sediment Weight (g)]/[Mean Wet Sediment Volume (mL)] = WetSediment Density (g/mL)  [2]    3. To determine the amount of base fluid needed to obtain a testconcentration of 500 mg base fluid per kg dry sediment use thefollowing formulas:    Determine the amount of wet sediment required:[Wet Sediment Density (g/mL)]  x  [Volume of Sediment Required perConcentration (mL)] = Weight Wet Sediment Required per Conc. (g)[3]    Determine the amount of dry sediment in kilograms (kg) requiredfor each concentration:{[Wet Sediment per Concentration (g)]/[Mean Wet to Dry Ratio]}  x(1kg/1000g) = Dry Weight Sediment (kg)  [4]    Finally, determine the amount of base fluid required to spikethe control sediment at each concentration:[Conc. Desired (mg/kg)]  x  [Dry Weight Sediment (kg)] = Base FluidRequired (mg)  [5]    For spiking test substances other than pure base fluids (e.g.,whole mud formulations), determine the spike amount as follows:[Conc. Desired (mL/kg)]  x  [Dry Weight Sediment (kg)]  x  [TestSubstance Density (g/mL)] = Test Substance Required (g)  [6]    4. For primary mixing, place appropriate amounts of weighed basefluid into stainless mixing bowls, tare the vessel weight, then addsediment and mix with a high-shear dispersing impeller for 9minutes. The concentration of base fluid in sediment from this mix,rather than the nominal concentration, shall be used in calculatingLC50 values.    5. Tests for homogeneity of base fluid in sediment are to beperformed during the procedure development phase. Because of[[Page 6902]]difficulty of homogeneously mixing base fluid with sediment, it isimportant to demonstrate that the base fluid is evenly mixed withsediment. The sediment shall be analyzed for total petroleumhydrocarbons (TPH) using EPA Methods 3550A and 8015M, with samplestaken both prior to and after distribution to replicate testcontainers. Base-fluid content is measured as TPH. After mixing thesediment, a minimum of three replicate sediment samples shall betaken prior to distribution into test containers. After the testsediment is distributed to test containers, an additional threesediment samples shall be taken from three test containers to ensureproper distribution of base fluid within test containers. Base-fluidcontent results shall be reported within 48 hours of mixing. Thecoefficient of variation (CV) for the replicate samples must be lessthan 20%. If base-fluid content results are not within the 20% CVlimit, the test sediment shall be remixed. Tests shall not beginuntil the CV is determined to be below the maximum limit of 20%.During the test, a minimum of three replicate containers shall besampled to determine base-fluid content during each sampling period.    6. Mix enough sediment in this way to allow for its use in thepreparation of all test concentrations and as a negative control.When commencing the sediment toxicity test, range-finding tests maybe required to determine the concentrations that produce a toxiceffect if these data are otherwise unavailable. The definitive testshall bracket the LC50, which is the desired endpoint.The results for the base fluids shall be reported in mg of basefluid per kg of dry sediment.References    American Society for Testing and Materials (ASTM). 1996.Standard Guide for Collection, Storage, Characterization, andManipulation of Sediments for Toxicological Testing. ASTM E 1391-94.Annual Book of ASTM Standards, Volume 11.05, pp. 805-825.    Ditsworth, G.R., D.W. Schults and J.K.P. Jones. 1990.Preparation of benthic substrates for sediment toxicity testing,Environ. Toxicol. Chem. 9:1523-1529.    Suedel, B.C., J.H. Rodgers, Jr. and P.A. Clifford. 1993.Bioavailability of fluoranthene in freshwater sediment toxicitytests. Environ. Toxicol. Chem. 12:155-165.    U.S. EPA. 1994. Methods for Assessing the Toxicity of Sediment-associated Contaminants with Estuarine and Marine Amphipods. EPA/600/R-94/025. Office of Research and Development, Washington, DC.Appendix 4 to Subpart A of Part 435--Determination of Biodegradation ofSynthetic Base Fluids in a Marine Closed Bottle Test System: Summary ofModifications to ISO 11734:1995    The six modifications specified in this Appendix shall apply tothe determination of the biodegradability of synthetic base fluidsas measured by ISO 11734:1995. These modifications make the testmore applicable to a marine environment and are listed below:    1.  The laboratory shall use sea water in place of freshwatermedia.    1.1  The sea water may be either natural or synthetic. Theallowable salinity range is 20-30 ppt.    1.2  To reduce the shock to the microorganisms in the sediment,the salinity of the sediment's porewater shall be between 20-30 ppt.    2.  The laboratory shall use natural marine or estuarinesediments in place of digested sludge as an inoculum. The VS of thesediments must be no less than 2%.    2.1  Sediment should be used for testing as soon as possibleafter field collection. If required, the laboratory can store thesediment for a maximum period of two months prior to use. The testsediment shall be stored in the dark at 4 deg.C.    2.2  The laboratory shall use the sediment mixing procedurespecified in Appendix 3 to Subpart A of part 435 to spike the testsediment with base fluids. The final concentration will be 2000 mgcarbon/Kg dry weight sediment. No less than 25 g dry weight of thespiked sediment shall be used per 125 ml serum bottle. The volume ofsediment and seawater in the bottle shall be 75 ml.    3.  The temperature of incubation shall be291 deg.C.    4.  The pH is maintained at the level of natural sea water, notat 7.0 as referenced in ISO 11734:1995.    5.  The optional use of a trace metals solution as specified inmethod ISO 11734:1995 shall not be used as part of these testmodifications.    6.  The laboratory shall conduct the test for 275 days. Thelaboratory may seek approval of alternate test durations under theapproval procedures specified at 40 CFR 136.4 and 136.5. Anymodification of this method, beyond those expressly permitted, shallbe considered a major modification subject to application andapproval of alternate test procedures under 40 CFR 136.4 and 136.5.Appendix 5 to Subpart A of Part 435--Determination of Crude OilContamination in Non-Aqueous Drilling Fluids by Gas Chromatography/MassSpectrometry (GC/MS)1.0  Scope and Application    1.1  This method determines crude (formation) oil contamination,or other petroleum oil contamination, in non-aqueous drilling fluids(NAFs) by comparing the gas chromatography/mass spectrometry (GC/MS)fingerprint scan and extracted ion scans of the test sample to thatof an uncontaminated sample.    1.2  This method can be used for monitoring oil contamination ofNAFs or monitoring oil contamination of the base fluid used in theNAF formulations.    1.3  Any modification of this method beyond those expresslypermitted shall be considered as a major modification subject toapplication and approval of alternative test procedures under 40 CFR136.4 and 136.5.    1.4  The gas chromatography/mass spectrometry portions of thismethod are restricted to use by, or under the supervision ofanalysts experienced in the use of GC/MS and in the interpretationof gas chromatograms and extracted ion scans. Each laboratory thatuses this method must generate acceptable results using theprocedures described in Sections 7, 9.2, and 12 of this appendix.2.0  Summary of Method    2.1  Analysis of NAF for crude oil contamination is a step-wiseprocess. The analyst first performs a qualitative assessment of thepresence or absence of crude oil in the sample. If crude oil isdetected during this qualitative assessment, the analyst mustperform a quantitative analysis of the crude oil concentration.    2.2  A sample of NAF is centrifuged to obtain a solids freesupernate.    2.3  The test sample is prepared by removing an aliquot of thesolids free supernate, spiking it with internal standard, andanalyzing it using GC/MS techniques. The components are separated bythe gas chromatograph and detected by the mass spectrometer.    2.4  Qualitative identification of crude oil contamination isperformed by comparing the Total Ion Chromatograph (TIC) scans andExtracted Ion Profile (EIP) scans of test sample to that ofuncontaminated base fluids, and examining the profiles forchromatographic signatures diagnostic of oil contamination.    2.5  The presence or absence of crude oil contamination observedin the full scan profiles and selected extracted ion profilesdetermines further sample quantitation and reporting requirements.    2.6  If crude oil is detected in the qualitative analysis,quantitative analysis must be performed by calibrating the GC/MSusing a designated NAF spiked with known concentrations of adesignated oil.    2.7  Quality is assured through reproducible calibration andtesting of GC/MS system and through analysis of quality controlsamples.3.0  Definitions    3.1  A NAF is one in which the continuous-- phase is a waterimmiscible fluid such as an oleaginous material (e.g., mineral oil,enhance mineral oil, paraffinic oil, or synthetic material such asolefins and vegetable esters).    3.2  TIC--Total Ion Chromatograph.    3.3  EIP--Extracted Ion Profile.    3.4  TCB--1,3,5-trichlorobenzene is used as the internalstandard in this method.    3.5  SPTM--System Performance Test Mix standards are used toestablish retention times and monitor detection levels.4.0  Interferences and Limitations    4.1  Solvents, reagents, glassware, and other sample processinghardware may yield artifacts and/or elevated baselines causingmisinterpretation of chromatograms.    4.2  All Materials used in the analysis shall be demonstrated tobe free from interferences by running method blanks. Specificselection of reagents and purification of solvents by distillationin all-glass systems may be required.    4.3  Glassware shall be cleaned by rinsing with solvent andbaking at 400  deg.C for a minimum of 1 hour.[[Page 6903]]    4.4  Interferences may vary from source to source, depending onthe diversity of the samples being tested.    4.5  Variations in and additions of base fluids and/or drillingfluid additives (emulsifiers, dispersants, fluid loss controlagents, etc.) might also cause interferences and misinterpretationof chromatograms.    4.6  Difference in light crude oils, medium crude oils, andheavy crude oils will result in different responses and thusdifferent interpretation of scans and calculated percentages.5.0  Safety    5.1  The toxicity or carcinogenicity of each reagent used inthis method has not been precisely determined; however each chemicalshall be treated as a potential health hazard. Exposure to thesechemicals should be reduced to the lowest possible level.    5.2  Unknown samples may contain high concentration of volatiletoxic compounds. Sample containers should be opened in a hood andhandled with gloves to prevent exposure. In addition, all samplepreparation should be conducted in a fume hood to limit thepotential exposure to harmful contaminates.    5.3  This method does not address all safety issues associatedwith its use. The laboratory is responsible for maintaining a safework environment and a current awareness file of OSHA regulationsregarding the safe handling of the chemicals specified in thismethod. A reference file of material safety data sheets (MSDSs)shall be available to all personnel involved in these analyses.Additional references to laboratory safety can be found inReferences 16.1 through 16.3.    5.4  NAF base fluids may cause skin irritation, protectivegloves are recommended while handling these samples.6.0  Apparatus and Materials    Note: Brand names, suppliers, and part numbers are forillustrative purposes only. No endorsement is implied. Equivalentperformance may be achieved using apparatus and materials other thanthose specified here, but demonstration of equivalent performancemeeting the requirements of this method is the responsibility of thelaboratory.    6.1  Equipment for glassware cleaning.    6.1.1  Laboratory sink with overhead fume hood.    6.1.2  Kiln--Capable of reaching 450  deg.C within 2 hours andholding 450  deg.C within 10  deg.C, with temperaturecontroller and safety switch (Cress Manufacturing Co., Santa FeSprings, CA B31H or X31TS or equivalent).    6.2  Equipment for sample preparation.    6.2.1  Laboratory fume hood.    6.2.2  Analytical balance--Capable of weighing 0.1 mg.    6.2.3  Glassware.    6.2.3.1  Disposable pipettes--Pasteur, 150 mm long by 5 mm ID(Fisher Scientific 13-678-6A, or equivalent) baked at 400  deg.C fora minimum of 1 hour.    6.2.3.2  Glass volumetric pipettes or gas tight syringes--1.0-mL 1% and 0.5-mL  1%.    6.2.3.3  Volumetric flasks--Glass, class A, 10-mL, 50-mL and100-mL.    6.2.3.4--Sample vials--Glass, 1- to 3-mL (baked at 400  deg.Cfor a minimum of 1 hour) with PTFE-lined screw or crimp cap.    6.2.3.5  Centrifuge and centrifuge tubes--Centrifuge capable of10,000 rpm, or better, (International Equipment Co., IEC Centra MP4or equivalent) and 50-mL centrifuge tubes (Nalgene, Ultratube, ThinWall 25 x 89 mm, #3410-2539).    6.3  Gas Chromatograph/Mass Spectrometer (GC/MS):    6.3.1  Gas Chromatograph--An analytical system complete with atemperature-programmable gas chromatograph suitable for split/splitless injection and all required accessories, includingsyringes, analytical columns, and gases.    6.3.1.1  Column--30 m (or 60 m)  x  0.32 mm ID (or 0.25 mm ID)1m film thickness (or 0.25m film thickness)silicone-coated fused-silica capillary column (J&W Scientific DB-5or equivalent).    6.3.2  Mass Spectrometer--Capable of scanning from 35 to 500 amuevery 1 sec or less, using 70 volts (nominal) electron energy in theelectron impact ionization mode (Hewlett Packard 5970MS orcomparable).    6.3.3  GC/MS interface--the interface is a capillary-directinterface from the GC to the MS.    6.3.4--Data system--A computer system must be interfaced to themass spectrometer. The system must allow the continuous acquisitionand storage on machine-readable media of all mass spectra obtainedthroughout the duration of the chromatographic program. The computermust have software that can search any GC/MS data file for ions of aspecific mass and that can plot such ion abundance versus retentiontime or scan number. This type of plot is defined as an ExtractedIon Current Profile (EIP). Software must also be available thatallows integrating the abundance in any total ion chromatogram (TIC)or EIP between specified retention time or scan-number limits. It isadvisable that the most recent version of the EPA/NIST Mass SpectralLibrary be available.7.0  Reagents and Standards    7.1  Methylene chloride--Pesticide grade or equivalent. Use whennecessary for sample dilution.    7.2  Standards--Prepare from pure individual standard materialsor purchase as certified solutions. If compound purity is 96% orgreater, the weight may be used without correction to compute theconcentration of the standard.    7.2.1  Crude Oil Reference--Obtain a sample of a crude oil witha known API gravity. This oil shall be used in the calibrationprocedures.    7.2.2  Synthetic Base Fluid--Obtain a sample of clean internalolefin (IO) Lab drilling fluid (as sent from the supplier--has notbeen circulated downhole). This drilling fluid shall be used in thecalibration procedures.    7.2.3  Internal standard--Prepare a 0.01 g/mL solution of 1,3,5-trichlorobenzene (TCB). Dissolve 1.0 g of TCB in methylene chlorideand dilute to volume in a 100-mL volumetric flask. Stopper, vortex,and transfer the solution to a 150-mL bottle with PTFE-lined cap.Label appropriately, and store at -5  deg.C to 20  deg.C. Mark thelevel of the meniscus on the bottle to detect solvent loss.    7.2.4  GC/MS system performance test mix (SPTM) standards--TheSPTM standards shall contain octane, decane, dodecane, tetradecane,tetradecene, toluene, ethylbenzene, 1,2,4-trimethylbenzene, 1-methylnaphthalene and 1,3-dimethylnaphthalene. These compounds canbe purchased individually or obtained as a mixture (i.e. Supelco,Catalog No. 4-7300). Prepare a high concentration of the SPTMstandard at 62.5 mg/mL in methylene chloride. Prepare a mediumconcentration SPTM standard at 1.25 mg/mL by transferring 1.0 mL ofthe 62.5 mg/mL solution into a 50 mL volumetric flask and dilutingto the mark with methylene chloride. Finally, prepare a lowconcentration SPTM standard at 0.125 mg/mL by transferring 1.0 mL ofthe 1.25 mg/mL solution into a 10-mL volumetric flask and dilutingto the mark with methylene chloride.    7.2.5  Crude oil/drilling fluid calibration standards--Prepare a4-point crude oil/drilling fluid calibration at concentrations of 0%(no spike--clean drilling fluid), 0.5%, 1.0%, and 2.0% by weightaccording to the procedures outlined in this appendix using theReference Crude Oil:    7.2.5.1  Label 4 jars with the following identification: Jar 1--0%Ref-IOLab, Jar 2--0.5%Ref-IOLab, Jar 3--1%Ref-IOLab, and Jar 4--2%Ref-IOLab.    7.2.5.2  Weigh 4, 50-g aliquots of well mixed IO Lab drillingfluid into each of the 4 jars.    7.2.5.3  Add Reference Oil at 0.5%, 1.0%, and 2.0% by weight tojars 2, 3, and 4 respectively. Jar 1 shall not be spiked withReference Oil in order to retain a ``0%'' oil concentration.    7.2.5.4  Thoroughly mix the contents of each of the 4 jars,using clean glass stirring rods.    7.2.5.5  Transfer (weigh) a 30-g aliquot from Jar 1 to a labeledcentrifuge tube. Centrifuge the aliquot for a minimum of 15 min atapproximately 15,000 rpm, in order to obtain a solids freesupernate. Weigh 0.5 g of the supernate directly into a tared andappropriately labeled GC straight vial. Spike the 0.5-g supernatewith 500 L of the 0.01g/mL 1,3,5-trichlorobenzene internalstandard solution (see Section 7.2.3 of this appendix), cap with aTeflon lined crimp cap, and vortex for ca. 10 sec.    7.2.5.6  Repeat step 7.2.5.5 except use an aliquot from Jar 2.    7.2.5.7  Repeat step 7.2.5.5 except use an aliquot from Jar 3.    7.2.5.8  Repeat step 7.2.5.5 except use an aliquot from Jar 4.    7.2.5.9  These 4 crude/oil drilling fluid calibration standardsare now used for qualitative and quantitative GC/MS analysis.    7.2.6  Precision and recovery standard (mid level crude oil/drilling fluid calibration standard)--Prepare a mid point crude oil/drilling fluid calibration using IO Lab drilling fluid and ReferenceOil at a concentration of 1.0% by weight. Prepare this standardaccording to the procedures outlined in Section 7.2.5.1 through7.2.5.5 of this appendix, with the exception that only ``Jar[[Page 6904]]3'' needs to be prepared. Remove and spike with internal standard,as many 0.5-g aliquots as needed to complete the GC/MS analysis (seeSection 11.6 of this appendix--bracketing authentic samples every 12hours with precision and recovery standard) and the initialdemonstration exercise described in Section 9.2 of this appendix.    7.2.7  Stability of standards    7.2.7.1  When not used, standards shall be stored in the dark,at -5 to -20  deg.C in screw-capped vials with PTFE-lined lids.Place a mark on the vial at the level of the solution so thatsolvent loss by evaporation can be detected. Bring the vial to roomtemperature prior to use.    7.2.7.2  Solutions used for quantitative purposes shall beanalyzed within 48 hours of preparation and on a monthly basisthereafter for signs of degradation. A standard shall remainacceptable if the peak area remains within 15% of thearea obtained in the initial analysis of the standard.8.0  Sample Collection Preservation and Storage    8.1  Collect NAF and base fluid samples in 100- to 200-mL glassbottles with PTFE- or aluminum foil lined caps.    8.2  Samples collected in the field shall be stored refrigerateduntil time of preparation.    8.3  Sample and extract holding times for this method have notyet been established. However, based on initial experience with themethod, samples should be analyzed within seven to ten days ofcollection and extracts should be analyzed within seven days ofpreparation.    8.4  After completion of GC/MS analysis, extracts shall berefrigerated at 4  deg.C until further notification of sampledisposal.9.0  Quality Control    9.1  Each laboratory that uses this method is required tooperate a formal quality assurance program (Reference 16.4). Theminimum requirements of this program shall consist of an initialdemonstration of laboratory capability, and ongoing analysis ofstandards, and blanks as a test of continued performance, analysesof spiked samples to assess accuracy and analysis of duplicates toassess precision. Laboratory performance shall be compared toestablished performance criteria to determine if the results ofanalyses meet the performance characteristics of the method.    9.1.1  The analyst shall make an initial demonstration of theability to generate acceptable accuracy and precision with thismethod. This ability shall be established as described in Section9.2 of this appendix.    9.1.2  The analyst is permitted to modify this method to improveseparations or lower the cost of measurements, provided allperformance requirements are met. Each time a modification is madeto the method, the analyst is required to repeat the calibration(Section 10.4 of this appendix) and to repeat the initialdemonstration procedure described in Section 9.2 of this appendix.    9.1.3  Analyses of blanks are required to demonstrate freedomfrom contamination. The procedures and criteria for analysis of ablank are described in Section 9.3 of this appendix.    9.1.4  Analysis of a matrix spike sample is required todemonstrate method accuracy. The procedure and QC criteria forspiking are described in Section 9.4 of this appendix.    9.1.5  Analysis of a duplicate field sample is required todemonstrate method precision. The procedure and QC criteria forduplicates are described in Section 9.5 of this appendix.    9.1.6  Analysis of a sample of the clean NAF(s) (as sent fromthe supplier--i.e., has not been circulated downhole) used in thedrilling operations is required.    9.1.7  The laboratory shall, on an ongoing basis, demonstratethrough calibration verification and the analysis of the precisionand recovery standard (Section 7.2.6 of this appendix) that theanalysis system is in control. These procedures are described inSection 11.6 of this appendix.    9.1.8  The laboratory shall maintain records to define thequality of data that is generated.    9.2  Initial precision and accuracy--The initial precision andrecovery test shall be performed using the precision and recoverystandard (1% by weight Reference Oil in IO Lab drilling fluid). Thelaboratory shall generate acceptable precision and recovery byperforming the following operations.    9.2.1  Prepare four separate aliquots of the precision andrecovery standard using the procedure outlined in Section 7.2.6 ofthis appendix. Analyze these aliquots using the procedures outlinedin Section 11 of this appendix.    9.2.2  Using the results of the set of four analyses, computethe average recovery (X) in weight percent and the standarddeviation of the recovery(s) for each sample.    9.2.3  If s and X meet the acceptance criteria of 80% to 110%,system performance is acceptable and analysis of samples may begin.If, however, s exceeds the precision limit or X falls outside therange for accuracy, system performance is unacceptable. In thisevent, review this method, correct the problem, and repeat the test.    9.2.4  Accuracy and precision--The average percent recovery (P)and the standard deviation of the percent recovery (Sp) Express theaccuracy assessment as a percent recovery interval from P-2Sp to P+2Sp. For example, if P=90% andSp=10% for four analyses of crude oil in NAF, theaccuracy interval is expressed as 70% to 110%. Update the accuracyassessment on a regular basis.    9.3  Blanks--Rinse glassware and centrifuge tubes used in themethod with 30 mL of methylene chloride, remove a 0.5-g aliquot ofthe solvent, spike it with the 500 L of the internalstandard solution (Section 7.2.3 of this appendix) and analyze a 1-L aliquot of the blank sample using the procedure inSection 11 of this appendix. Compute results per Section 12 of thisappendix.    9.4  Matrix spike sample--Prepare a matrix spike sampleaccording to procedure outlined in Section 7.2.6 of this appendix.Analyze the sample and calculate the concentration (% oil) in thedrilling fluid and % recovery of oil from the spiked drilling fluidusing the methods described in Sections 11 and 12 of this appendix.    9.5  Duplicates--A duplicate field sample shall be preparedaccording to procedures outlined in Section 7.3 of this appendix andanalyzed according to Section 11 of this appendix. The relativepercent difference (RPD) of the calculated concentrations shall beless than 15%.    9.5.1  Analyze each of the duplicates per the procedure inSection 11 of this appendix and compute the results per Section 12of this appendix.    9.5.2  Calculate the relative percent difference (RPD) betweenthe two results per the following equation:RPD = [D1 - D2]/[(D1 +D2)/2]  x  100  [1]where:D1 = Concentration of crude oil in the sample; andD2 = Concentration of crude oil in the duplicate sample.    9.5.3  If the RPD criteria are not met, the analytical systemshall be judged to be out of control, and the problem must beimmediately identified and corrected, and the sample batch re-analyzed.    9.6  Prepare the clean NAF sample according to proceduresoutlined in Section 7.3 of this appendix. Ultimately the oil-equivalent concentration from the TIC or EIP signal measured in theclean NAF sample shall be subtracted from the correspondingauthentic field samples in order to calculate the true contaminantconcentration (% oil) in the field samples (see Section 12 of thisappendix).    9.7  The specifications contained in this method can be met ifthe apparatus used is calibrated properly, and maintained in acalibrated state. The standards used for initial precision andrecovery (Section 9.2 of this appendix) and ongoing precision andrecovery (Section 11.6 of this appendix) shall be identical, so thatthe most precise results will be obtained. The GC/MS instrument willprovide the most reproducible results if dedicated to the settingand conditions required for the analyses given in this method.    9.8  Depending on specific program requirements, fieldreplicates and field spikes of crude oil into samples may berequired when this method is used to assess the precision andaccuracy of the sampling and sample transporting techniques.10.0  Calibration    10.1  Establish gas chromatographic/mass spectrometer operatingconditions given in Table 1 of this appendix. Perform the GC/MSsystem hardware-tune as outlined by the manufacture. The gaschromatograph shall be calibrated using the internal standardtechnique.    Note: Because each GC is slightly different, it may be necessaryto adjust the operating conditions (carrier gas flow rate and columntemperature and temperature program) slightly until the retentiontimes in Table 2 of this appendix are met.     Table 1.--Gas Chromatograph/Mass Spectrometer (GC/MS) Operation                               Conditions------------------------------------------------------------------------                 Parameter                             Setting------------------------------------------------------------------------Injection pot.............................  280  deg.C[[Page 6905]]Transfer line.............................  280  deg.CDetector..................................  280  deg.CInitial Temperature.......................  50  deg.CInitial Time..............................  5 minutesRamp......................................  50 to 300  deg.C @ 5  deg.C                                             per minuteFinal Temperature.........................  300  deg.CFinal Hold................................  20 minutes or until all                                             peaks have elutedCarrier Gas...............................  HeliumFlow rate.................................  As required for standard                                             operationSplit ratio...............................  As required to meet                                             performance criteria                                             (~1:100)Mass range................................  35 to 600 amu------------------------------------------------------------------------           Table 2.--Approximate Retention Time for Compounds------------------------------------------------------------------------                                                             Approximate                                                              retention                          Compound                               time                                                              (minutes)------------------------------------------------------------------------Toluene....................................................          5.6Octane, n-C8...............................................          7.2Ethylbenzene...............................................         10.31,2,4-Trimethylbenzene.....................................         16.0Decane, -C10...............................................         16.1TCB (Internal Standard)....................................         21.3Dodecane, -C12.............................................         22.91-Methylnaphthalene........................................         26.71-Tetradecene..............................................         28.4Tetradecane, -C14..........................................         28.71,3-Dimethylnaphthalene....................................         29.7------------------------------------------------------------------------    10.2  Internal standard calibration procedure--1,3,5-trichlorobenzene (TCB) has been shown to be free of interferencesfrom diesel and crude oils and is a suitable internal standard.    10.3  The system performance test mix standards prepared inSection 7.2.4 of this appendix shall be used to establish retentiontimes and establish qualitative detection limits.    10.3.1  Spike a 500-mL aliquot of the 1.25 mg/mL SPTM standardwith 500 L of the TCB internal standard solution.    10.3.2  Inject 1.0 L of this spiked SPTM standard ontothe GC/MS in order to demonstrate proper retention times. For theGC/MS used in the development of this method, the ten compounds inthe mixture had typical retention times shown in Table 2 of thisappendix. Extracted ion scans for m/z 91 and 105 showed a maximumabundance of 400,000.    10.3.3  Spike a 500-mL aliquot of the 0.125 mg/mL SPTM standardwith 500 L of the TCB internal standard solution.    10.3.4  Inject 1.0 L of this spiked SPTM standard ontothe GC/MS to monitor detectable levels. For the GC/MS used in thedevelopment of this test, all ten compounds showed a minimum peakheight of three times signal to noise. Extracted ion scans for m/z91 and 105 showed a maximum abundance of 40,000.    10.4  GC/MS crude oil/drilling fluid calibration--There are twomethods of quantification: Total Area Integration (C8-C13) and EIP Area Integration using m/z's 91 and 105. TheTotal Area Integration method should be used as the primarytechnique for quantifying crude oil in NAFs. The EIP AreaIntegration method should be used as a confirmatory technique forNAFs. However, the EIP Area Integration method shall be used as theprimary method for quantifying oil in enhanced mineral oil (EMO)based drilling fluid. Inject 1.0 L of each of the fourcrude oil/drilling fluid calibration standards prepared in Section7.2.5 of this appendix into the GC/MS. The internal standard shouldelute approximately 21-22 minutes after injection. For the GC/MSused in the development of this method, the internal standard peakwas (35 to 40)% of full scale at an abundance of about 3.5e+07.    10.4.1  Total Area Integration Method--For each of the fourcalibration standards obtain the following: Using a straightbaseline integration technique, obtain the total ion chromatogram(TIC) area from C8 to C13. Obtain the TIC areaof the internal standard (TCB). Subtract the TCB area from theC8-C13 area to obtain the true C8-C13 area. Using the C8-C13 and TCBareas, and known internal standard concentration, generate a linearregression calibration using the internal standard method. Ther2 value for the linear regression curve shall be greaterthan or equal to 0.998. Some synthetic fluids might have peaks thatelute in the window and would interfere with the analysis. In thiscase the integration window can be shifted to other areas of scanwhere there are no interfering peaks from the synthetic base fluid.    10.4.2  EIP Area Integration--For each of the four calibrationstandards generate Extracted Ion Profiles (EIPs) for m/z 91 and 105.Using straight baseline integration techniques, obtain the followingEIP areas:    10.4.2.1  For m/z 91 integrate the area under the curve fromapproximately 9 minutes to 21-22 minutes, just prior to but notincluding the internal standard.    10.4.2.2  For m/z 105 integrate the area under the curve fromapproximately 10.5 minutes to 26.5 minutes.    10.4.2.3  Obtain the internal standard area from the TCB in eachof the four calibration standards, using m/z 180.    10.4.2.4  Using the EIP areas for TCB, m/z 91 and m/z105, andthe known concentration of internal standard, generate linearregression calibration curves for the target ions 91 and 105 usingthe internal standard method. The r2 value for each ofthe EIP linear regression curves shall be greater than or equal to0.998.    10.4.2.5  Some base fluids might produce a background level thatwould show up on the extracted ion profiles, but there should not beany real peaks (signal to noise ratio of 1:3) from the clean basefluids.11.0  Procedure    11.1  Sample Preparation--    11.1.1  Mix the authentic field sample (drilling fluid) well.Transfer (weigh) a 30-g aliquot of the sample to a labeledcentrifuge tube.    11.1.2  Centrifuge the aliquot for a minimum of 15 min atapproximately 15,000 rpm, in order to obtain a solids freesupernate.    11.1.3  Weigh 0.5 g of the supernate directly into a tared andappropriately labeled GC straight vial.    11.1.4  Spike the 0.5-g supernate with 500 L of the0.01g/mL 1,3,5-trichlorobenzene internal standard solution (seeSection 7.2.3 of this appendix), cap with a Teflon lined crimp cap,and vortex for ca. 10 sec.    11.1.5  The sample is ready for GC/MS analysis.    11.2  Gas Chromatography.    Table 1 of this appendix summarizes the recommended operatingconditions for the GC/MS. Retention times for the n-alkanes obtainedunder these conditions are given in Table 2 of this appendix. Othercolumns, chromatographic conditions, or detectors may be used ifinitial precision and accuracy requirements (Section 9.2 of thisappendix) are met. The system shall be calibrated according to theprocedures outlined in Section 10 of this appendix, and verifiedevery 12 hours according to Section 11.6 of this appendix.    11.2.1  Samples shall be prepared (extracted) in a batch of nomore than 20 samples. The batch shall consist of 20 authenticsamples, 1 blank (Section 9.3 of this appendix), 1 matrix spikesample (9.4), and 1 duplicate field sample (9.5), and a preparedsample of the corresponding clean NAF used in the drilling process.    11.2.2  An analytical sequence shall be analyzed on the GC/MSwhere the 3 SPTM standards (Section 7.2.4 of this appendix)containing internal standard are analyzed first, followed byanalysis of the four GC/MS crude oil/drilling fluid calibrationstandards (Section 7.2.5 of this appendix), analysis of the blank,matrix spike sample, the duplicate sample, the clean NAF sample,followed by the authentic samples.    11.2.3  Samples requiring dilution due to excessive signal shallbe diluted using methylene chloride.    11.2.4  Inject 1.0 L of the test sample or standardinto the GC, using the conditions in Table 1 of this appendix.    11.2.5  Begin data collection and the temperature program at thetime of injection.    11.2.6  Obtain a TIC and EIP fingerprint scans of the sample(Table 3 of this appendix).    11.2.7  If the area of the C8 to C13 peaksexceeds the calibration range of the system, dilute a fresh aliquotof the test sample weighing 0.50-g and re-analyze.    11.2.8  Determine the C8 to C13 TIC area,the TCB internal standard area, and the areas for the m/z 91 and 105EIPs. These shall be used in the calculation of oil concentration inthe samples (see Section 12 of this appendix).[[Page 6906]]                 Table 3.--Recommended Ion Mass Numbers------------------------------------------------------------------------                                     Corresponding    Typical rentention    Selected ion mass numbers     aromatic compounds    time (minutes)------------------------------------------------------------------------91..............................  Methylbenzene.....                6.0                                  Ethylbenzene......               10.3                                  1,4-                             10.9                                   Dimethylbenzene.                                  1,3-                             10.9                                   Dimethylbenzene.                                  1,2-                             11.9                                   Dimethylbenzene.105.............................  1,3,5-                           15.1                                   Trimethylbenzene.                                  1,2,4-                           16.0                                   Trimethylbenzene.                                  1,2,3-                           17.4                                   Trimethylbenzene.156.............................  2,6-                             28.9                                   Dimethylnaphthale                                   ne.                                  1,2-                             29.4                                   Dimethylnaphthale                                   ne.                                  1,3-                             29.7                                   Dimethylnaphthale                                   ne.------------------------------------------------------------------------    11.2.9  Observe the presence of peaks in the EIPs that wouldconfirm the presence of any target aromatic compounds. Using the EIPareas and EIP linear regression calibrations compare the abundanceof the aromatic peaks, and if appropriate, determine approximatecrude oil contamination in the sample for each of the target ions.    11.3  Qualitative Identification--See Section 17 of thisappendix for schematic flowchart.    11.3.1  Qualitative identification shall be accomplished bycomparison of the TIC and EIP area data from an authentic sample tothe TIC and EIP area data from the calibration standards (Section12.4 of this appendix). Crude oil shall be identified by thepresence of C10 to C13 n-alkanes andcorresponding target aromatics.    11.3.2  Using the calibration data, establish the identity ofthe C8 to C13 peaks in the chromatogram of thesample. Using the calibration data, establish the identity of anytarget aromatics present on the extracted ion scans.    11.3.3  Crude oil is not present in a detectable amount in thesample if there are no target aromatics seen on the extracted ionscans. The experience of the analyst shall weigh heavily in thedetermination of the presence of peaks at a signal-to-noise ratio of3 or greater.    11.3.4  If the chromatogram shows n-alkanes from C8to C13 and target aromatics to be present, contaminationby crude oil or diesel shall be suspected and quantitative analysisshall be determined. If there are no n-alkanes present that are notseen on the blank, and no target aromatics are seen, the sample canbe considered to be free of contamination.    11.4  Quantitative Identification--    11.4.1  Determine the area of the peaks from C8 toC13 as outlined in the calibration section (10.4.1 ofthis appendix). If the area of the peaks for the sample is greaterthan that for the clean NAF (base fluid) use the crude oil/drillingfluid calibration TIC linear regression curve to determineapproximate crude oil contamination.    11.4.2  Using the EIPs outlined in Section 10.4.2 of thisappendix, determine the presence of any target aromatics. Using theintegration techniques outlined in Section 10.4.2 of this appendix,obtain the EIP areas for m/z 91 and 105. Use the crude oil/drillingfluid calibration EIP linear regression curves to determineapproximate crude oil contamination.    11.5  Complex Samples--    11.5.1  The most common interferences in the determination ofcrude oil can be from mineral oil, diesel oil, and proprietaryadditives in drilling fluids.    11.5.2  Mineral oil can typically be identified by its lowertarget aromatic content, and narrow range of strong peaks.    11.5.3  Diesel oil can typically be identified by low amounts ofn-alkanes from C7 to C9, and the absence of n-alkanes greater than C25.    11.5.4  Crude oils can usually be distinguished by the presenceof high aromatics, increased intensities of C8 toC13 peaks, and/ or the presence of higher hydrocarbons ofC25 and greater (which may be difficult to see in somesynthetic fluids at low contamination levels).    11.5.4.1  Oil condensates from gas wells are low in molecularweight and will normally produce strong chromatographic peaks in theC8-C13 range. If a sample of the gascondensate crude oil from the formation is available, the oil can bedistinguished from other potential sources of contamination by usingit to prepare a calibration standard.    11.5.4.2  Asphaltene crude oils with API gravity 20 may notproduce chromatographic peaks strong enough to show contamination atlevels of the calibration. Extracted ion peaks should be easier tosee than increased intensities for the C8 toC13 peaks. If a sample of asphaltene crude from theformation is available, a calibration standard shall be prepared.    11.6  System and Laboratory Performance--    11.6.1  At the beginning of each 8-hour shift during whichanalyses are performed, GC crude oil/drilling fluid calibration andsystem performance test mixes shall be verified. For these tests,analysis of the medium-level calibration standard (1-% Reference Oilin IO Lab drilling fluid, and 1.25 mg/mL SPTM with internalstandard) shall be used to verify all performance criteria.Adjustments and/or re-calibration (per Section 10 of this appendix)shall be performed until all performance criteria are met. Onlyafter all performance criteria are met may samples and blanks beanalyzed.    11.6.2  Inject 1.0 L of the medium-level GC/MS crudeoil/drilling fluid calibration standard into the GC instrumentaccording to the procedures in Section 11.2 of this appendix. Verifythat the linear regression curves for both TIC area and EIP areasare still valid using this continuing calibration standard.    11.6.3  After this analysis is complete, inject 1.0 Lof the 1.25 mg/mL SPTM (containing internal standard) into the GCinstrument and verify the proper retention times are met (see Table2 of this appendix).    11.6.4  Retention times--Retention time of the internalstandard. The absolute retention time of the TCB internal standardshall be within the range 21.0  0.5 minutes. Relativeretention times of the n-alkanes: The retention times of the n-alkanes relative to the TCB internal standard shall be similar tothose given in Table 2 of this appendix.12.0  Calculations    The concentration of oil in NAFs drilling fluids shall becomputed relative to peak areas between C8 andC13 (using the Total Area Integration method) or totalpeak areas from extracted ion profiles (using the Extracted IonProfile Method). In either case, there is a measurable amount ofpeak area, even in clean drilling fluid samples, due to spuriouspeaks and electrometer ``noise'' that contributes to the totalsignal measured using either of the quantification methods. In thisprocedure, a correction for this signal is applied, using the blankor clean sample correction technique described in American Societyfor Testing Materials (ASTM) Method D-3328-90, Comparison ofWaterborne Oil by Gas Chromatography. In this method, the ``oilequivalents'' measured in a blank sample by total area gaschromatography are subtracted from that determined for a fieldsample to arrive at the most accurate measure of oil residue in theauthentic sample.    12.1  Total Area Integration Method    12.1.1  Using C8 to C13 TIC area, the TCBarea in the clean NAF sample and the TIC linear regression curve,compute the oil equivalent concentration of the C8 toC13 retention time range in the clean NAF.    Note: The actual TIC area of the C8 to C13is equal to the C8 to C13 area minus the areaof the TCB.    12.1.2  Using the corresponding information for the authenticsample, compute the oil equivalent concentration of theC8 to C13 retention time range in theauthentic sample.    12.1.3  Calculate the concentration (% oil) of oil in the sampleby subtracting the oil[[Page 6907]]equivalent concentration (% oil) found in the clean NAF from the oilequivalent concentration (% oil) found in the authentic sample.    12.2  EIP Area Integration Method    12.2.1  Using either m/z 91 or 105 EIP areas, the TCB area inthe clean NAF sample, and the appropriate EIP linear regressioncurve, compute the oil equivalent concentration of the in the cleanNAF.    12.2.2  Using the corresponding information for the authenticsample, compute its oil equivalent concentration.    12.2.3  Calculate the concentration (% oil) of oil in the sampleby subtracting the oil equivalent concentration (% oil) found in theclean NAF from the oil equivalent concentration (% oil) found in theauthentic sample.13.0  Method Performance    13.1  Specification in this method are adopted from EPA Method1663, Differentiation of Diesel and Crude Oil by GC/FID (Reference16.5).    13.2  Single laboratory method performance using an InternalOlefin (IO) drilling fluid fortified at 0.5% oil using a 35 APIgravity oil was:Precision and accuracy 944%Accuracy interval--86.3% to 102%Relative percent difference in duplicate analysis--6.2%14.0  Pollution Prevention    14.1  The solvent used in this method poses little threat to theenvironment when recycled and managed properly.15.0  Waste Management    15.1  It is the laboratory's responsibility to comply with allfederal, state, and local regulations governing waste management,particularly the hazardous waste identification rules and landdisposal restriction, and to protect the air, water, and land byminimizing and controlling all releases from fume hoods and benchoperations. Compliance with all sewage discharge permits andregulations is also required.    15.2  All authentic samples (drilling fluids) failing the RPE(fluorescence) test (indicated by the presence of fluorescence)shall be retained and classified as contaminated samples. Treatmentand ultimate fate of these samples is not outlined in this SOP.    15.3  For further information on waste management, consult ``TheWaste Management Manual for Laboratory Personnel'', and ``Less isBetter: Laboratory Chemical Management for Waste Reduction'', bothavailable from the American Chemical Society's Department ofGovernment Relations and Science Policy, 1155 16th Street NW,Washington, DC 20036.16.0  References    16.1  Carcinogens--``Working With Carcinogens.'' Department ofHealth, Education, and Welfare, Public Health Service, Centers forDisease Control (available through National Technical InformationSystems, 5285 Port Royal Road, Springfield, VA 22161, document no.PB-277256): August 1977.    16.2  ``OSHA Safety and Health Standards, General Industry [29CFR 1910], Revised.'' Occupational Safety and Health Administration,OSHA 2206. Washington, DC: January 1976.    16.3  ``Handbook of Analytical Quality Control in Water andWastewater Laboratories.'' USEPA, EMSSL-CI, EPA-600/4-79-019.Cincinnati, OH: March 1979.    16.4  ``Method 1663, Differentiation of Diesel and Crude Oil byGC/FID, Methods for the Determination of Diesel, Mineral, and CrudeOils in Offshore Oil and Gas Industry Discharges, EPA 821-R-92-008,Office of Water Engineering and Analysis Division, Washington, DC:December 1992.Appendix 6 to Subpart A of Part 435--Reverse Phase Extraction (RPE)Method for Detection of Oil Contamination in Non-Aqueous DrillingFluids (NAF)1.0  Scope and Application    1.1  This method is used for determination of crude or formationoil, or other petroleum oil contamination, in non-aqueous drillingfluids (NAFs).    1.2  This method is intended as a positive/negative test todetermine a presence of crude oil in NAF prior to discharging drillcuttings from offshore production platforms.    1.3  This method is for use in the Environmental ProtectionAgency's (EPA's) survey and monitoring programs under the CleanWater Act, including monitoring of compliance with the Gulf ofMexico NPDES General Permit for monitoring of oil contamination indrilling fluids.    1.4  This method has been designed to show positivecontamination for 5% of representative crude oils at a concentrationof 0.1% in drilling fluid (vol/vol), 50% of representative crudeoils at a concentration of 0.5%, and 95% of representative crudeoils at a concentration of 1%.    1.5  Any modification of this method, beyond those expresslypermitted, shall be considered a major modification subject toapplication and approval of alternate test procedures under 40 CFRParts 136.4 and 136.5.    1.6  Each laboratory that uses this method must demonstrate theability to generate acceptable results using the procedure inSection 9.2 of this appendix.2.0  Summary of Method    2.1  An aliquot of drilling fluid is extracted using isopropylalcohol.    2.2  The mixture is allowed to settle and then filtered toseparate out residual solids.    2.3  An aliquot of the filtered extract is charged onto areverse phase extraction (RPE) cartridge.    2.4  The cartridge is eluted with isopropyl alcohol.    2.5  Crude oil contaminates are retained on the cartridge andtheir presence (or absence) is detected based on observedfluorescence using a black light.3.0  Definitions    3.1  A NAF is one in which the continuous phase is a waterimmiscible fluid such as an oleaginous material (e.g., mineral oil,enhance mineral oil, paraffinic oil, or synthetic material such asolefins and vegetable esters).4.0  Interferences    4.1  Solvents, reagents, glassware, and other sample-processinghardware may yield artifacts that affect results. Specific selectionof reagents and purification of solvents may be required.    4.2  All materials used in the analysis shall be demonstrated tobe free from interferences under the conditions of analysis byrunning laboratory reagent blanks as described in Section 9.5 ofthis appendix.5.0  Safety    5.1  The toxicity or carcinogenicity of each reagent used inthis method has not been precisely determined; however, eachchemical shall be treated as a potential health hazard. Exposure tothese chemicals should be reduced to the lowest possible level.Material Safety Data Sheets (MSDSs) shall be available for allreagents.    5.2  Isopropyl alcohol is flammable and should be used in awell-ventilated area.    5.3  Unknown samples may contain high concentration of volatiletoxic compounds. Sample containers should be opened in a hood andhandled with gloves to prevent exposure. In addition, all samplepreparation should be conducted in a well-ventilated area to limitthe potential exposure to harmful contaminants. Drilling fluidsamples should be handled with the same precautions used in thedrilling fluid handling areas of the drilling rig.    5.4  This method does not address all safety issues associatedwith its use. The laboratory is responsible for maintaining a safework environment and a current awareness file of OSHA regulationsregarding the safe handling of the chemicals specified in thismethod. A reference file of material safety data sheets (MSDSs)shall be available to all personnel involved in these analyses.Additional information on laboratory safety can be found inReferences 16.1-16.2.6.0  Equipment and Supplies    Note: Brand names, suppliers, and part numbers are forillustrative purposes only. No endorsement is implied. Equivalentperformance may be achieved using apparatus and materials other thanthose specified here, but demonstration of equivalent performancethat meets the requirements of this method is the responsibility ofthe laboratory.    6.1  Sampling equipment.    6.1.1  Sample collection bottles/jars--New, pre-cleaned bottles/jars, lot-certified to be free of artifacts. Glass preferable,plastic acceptable, wide mouth approximately 1-L, with Teflon-linedscrew cap.    6.2  Equipment for glassware cleaning.    6.2.1  Laboratory sink.    6.2.2  Oven--Capable of maintaining a temperature within5 deg.C in the range of 100-250  deg.C.    6.3  Equipment for sample extraction.    6.3.1  Vials--Glass, 25 mL and 4 mL, with Teflon-lined screwcaps, baked at 200-250  deg.C for 1-h minimum prior to use.    6.3.2  Gas-tight syringes--Glass, various sizes, 0.5 mL to 2.5mL (if spiking of drilling fluids with oils is to occur).    6.3.3  Auto pipetters--various sizes, 0.1 mL, 0.5 mL, 1 to 5 mLdelivery, and 10 mL[[Page 6908]]delivery, with appropriate size disposable pipette tips, calibratedto within 0.5%.    6.3.4  Glass stirring rod.    6.3.5  Vortex mixer.    6.3.6  Disposable syringes--Plastic, 5 mL.    6.3.7  Teflon syringe filter, 25-mm, 0.45m pore size--Acrodisc CR Teflon (or equivalent).    6.3.8  Reverse Phase Extraction C18 Cartridge--WatersSep-PakPlus, C18 Cartridge, 360 mg of sorbent(or equivalent).    6.3.9  SPE vacuum manifold--Supelco Brand, 12 unit (orequivalent). Used as support for cartridge/syringe assembly only.Vacuum apparatus not required.    6.4  Equipment for fluorescence detection.    6.4.1  Black light--UV Lamp, Model UVG 11, Mineral Light Lamp,Shortwave 254 nm, or Longwave 365 nm, 15 volts, 60 Hz, 0.16 amps (orequivalent).    6.4.2  Black box--cartridge viewing area. A commerciallyavailable ultraviolet viewing cabinet with viewing lamp, oralternatively, a cardboard box or equivalent, approximately14" x 7.5" x 7.5" in size and painted flat black inside. Lamppositioned in fitted and sealed slot in center on top of box. Samplecartridges sit in a tray, ca. 6" from lamp. Cardboard flaps cut ontop panel and side of front panel for sample viewing and samplecartridge introduction, respectively.    6.4.3  Viewing platform for cartridges. Simple support (handmade vial tray--black in color) for cartridges so that they do notmove during the fluorescence testing.7.0  Reagents and Standards    7.1  Isopropyl alcohol--99% purity.    7.2  NAF--Appropriate NAF as sent from the supplier (has notbeen circulated downhole). Use the clean NAF corresponding to theNAF being used in the current drilling operation.    7.3  Standard crude oil--NIST SRM 1582 petroleum crude oil.8.0  Sample Collection, Preservation, and Storage    8.1 Collect approximately one liter of representative sample(NAF, which has been circulated downhole) in a glass bottle or jar.Cover with a Teflon lined cap. To allow for a potential need to re-analyze and/or re-process the sample, it is recommended that asecond sample aliquot be collected.    8.2  Label the sample appropriately.    8.3  All samples must be refrigerated at 0-4  deg.C from thetime of collection until extraction (40 CFR Part 136, Table II).    8.4  All samples must be analyzed within 28 days of the date andtime of collection (40 CFR Part 136, Table II).9.0  Quality Control    9.1  Each laboratory that uses this method is required tooperate a formal quality assurance program (Reference 16.3). Theminimum requirements of this program consist of an initialdemonstration of laboratory capability, and ongoing analyses ofblanks and spiked duplicates to assess accuracy and precision and todemonstrate continued performance. Each field sample is analyzed induplicate to demonstrate representativeness.    9.1.1  The analyst shall make an initial demonstration of theability to generate acceptable accuracy and precision with thismethod. This ability is established as described in Section 9.2 ofthis appendix.    9.1.2  Preparation and analysis of a set of spiked duplicatesamples to document accuracy and precision. The procedure for thepreparation and analysis of these samples is described in Section9.4 of this appendix.    9.1.3  Analyses of laboratory reagent blanks are required todemonstrate freedom from contamination. The procedure and criteriafor preparation and analysis of a reagent blank are described inSection 9.5 of this appendix.    9.1.4  The laboratory shall maintain records to define thequality of the data that is generated.    9.1.5  Accompanying QC for the determination of oil in NAF isrequired per analytical batch. An analytical batch is a set ofsamples extracted at the same time, to a maximum of 10 samples. Eachanalytical batch of 10 or fewer samples must be accompanied by alaboratory reagent blank (Section 9.5 of this appendix),corresponding NAF reference blanks (Section 9.6 of this appendix), aset of spiked duplicate samples blank (Section 9.4 of thisappendix), and duplicate analysis of each field sample. If greaterthan 10 samples are to be extracted at one time, the samples must beseparated into analytical batches of 10 or fewer samples.    9.2  Initial demonstration of laboratory capability. Todemonstrate the capability to perform the test, the analyst shallanalyze two representative unused drilling fluids (e.g., internalolefin-based drilling fluid, vegetable ester-based drilling fluid),each prepared separately containing 0.1%, 1%, and 2% or arepresentative oil. Each drilling fluid/concentration combinationshall be analyzed 10 times, and successful demonstration will yieldthe following average results for the data set:0.1% oil--Detected in 20% of samples1% oil--Detected in >75% of samples2% oil--Detected in 90% of samples    9.3  Sample duplicates.    9.3.1  The laboratory shall prepare and analyze (Section 11.2and 11.4 of this appendix) each authentic sample in duplicate, froma given sampling site or, if for compliance monitoring, from a givendischarge.    9.3.2  The duplicate samples must be compared versus theprepared corresponding NAF blank.    9.3.3  Prepare and analyze the duplicate samples according toprocedures outlined in Section 11 of this appendix.    9.3.4  The results of the duplicate analyses are acceptable ifeach of the results give the same response (fluorescence or nofluorescence). If the results are different, sample non-homogenicityissues may be a concern. Prepare the samples again, ensuring a well-mixed sample prior to extraction. Analyze the samples once again.    9.3.5  If different results are obtained for the duplicate asecond time, the analytical system is judged to be out of controland the problem shall be identified and corrected, and the samplesre-analyzed.    9.4  Spiked duplicates--Laboratory prepared spiked duplicatesare analyzed to demonstrate acceptable accuracy and precision.    9.4.1  Preparation and analysis of a set of spiked duplicatesamples with each set of no more than 10 field samples is requiredto demonstrate method accuracy and precision and to monitor matrixinterferences (interferences caused by the sample matrix). A fieldNAF sample expected to contain less than 0.5% crude oil (anddocumented to not fluoresce as part of the sample batch analysis)shall be spiked with 1% (by volume) of suitable reference crude oiland analyzed as field samples, as described in Section 11 of thisappendix. If no low-level drilling fluid is available, then theunused NAF can be used as the drilling fluid sample.    9.5  Laboratory reagent blanks--Laboratory reagent blanks areanalyzed to demonstrate freedom from contamination.    9.5.1  A reagent blank is prepared by passing 4 mL of theisopropyl alcohol through a Teflon syringe filter and collecting thefiltrate in a 4-mL glass vial. A Sep Pak C18cartridge is then preconditioned with 3 mL of isopropyl alcohol. A0.5-mL aliquot of the filtered isopropyl alcohol is added to thesyringe barrel along with 3.0 mL of isopropyl alcohol. The solventis passed through the preconditioned Sep Pak cartridge. Anadditional 2-mL of isopropyl alcohol is eluted through thecartridge. The cartridge is now considered the ``reagent blank''cartridge and is ready for viewing (analysis). Check the reagentblank cartridge under the black light for fluorescence. If theisopropyl alcohol and filter are clean, no fluorescence will beobserved.    9.5.2  If fluorescence is detected in the reagent blankcartridge, analysis of the samples is halted until the source ofcontamination is eliminated and a prepared reagent blank shows nofluorescence under a black light. All samples shall be associatedwith an uncontaminated method blank before the results may bereported for regulatory compliance purposes.    9.6  NAF reference blanks--NAF reference blanks are preparedfrom the NAFs sent from the supplier (NAF that has not beencirculated downhole) and used as the reference when viewing thefluorescence of the test samples.    9.6.1  A NAF reference blank is prepared identically to theauthentic samples. Place a 0.1 mL aliquot of the ``clean'' NAF intoa 25-mL glass vial. Add 10 mL of isopropyl alcohol to the vial. Capthe vial. Vortex the vial for approximately 10 sec. Allow the solidsto settle for approximately 15 minutes. Using a 5-mL syringe, drawup 4 mL of the extract and filter it through a PTFE syringe filter,collecting the filtrate in a 4-mL glass vial. Precondition a SepPak C18 cartridge with 3 mL of isopropylalcohol. Add a 0.5-mL aliquot of the filtered extract to the syringebarrel along with 3.0 mL of isopropyl alcohol. Pass the extract andsolvent through the preconditioned Sep Pak cartridge. Passan additional 2-mL of isopropyl alcohol through the cartridge. Thecartridge is now considered the NAF blank cartridge and is ready forviewing (analysis). This cartridge is used as the referencecartridge for determining the absence or presence of fluorescence inall authentic drilling fluid[[Page 6909]]samples that originate from the same NAF. That is, the specific NAFreference blank cartridge is put under the black light along with aprepared cartridge of an authentic sample originating from the sameNAF material. The fluorescence or absence of fluorescence in theauthentic sample cartridge is determined relative to the NAFreference cartridge.    9.6.2  Positive control solution, equivalent to 1% crude oilcontaminated mud extract, is prepared by dissolving 87 mg ofstandard crude oil into 10.00 mL of methylene chloride. Then mix 40L of this solution into 10.00 mL of IPA. Transfer 0.5 mL ofthis solution into a preconditioned C18 cartridge, followed by 2 mlof IPA.10.0  Calibration and Standardization    10.1  Calibration and standardization methods are not employedfor this procedure.11.0  Procedure    This method is a screening-level test. Precise and accurateresults can be obtained only by strict adherence to all details.    11.1  Preparation of the analytical batch.    11.1.1  Bring the analytical batch of samples to roomtemperature.    11.1.2  Using a large glass stirring rod, mix the authenticsample thoroughly.    11.1.3  Using a large glass stirring rod, mix the clean NAF(sent from the supplier) thoroughly.    11.2  Extraction.    11.2.1  Using an automatic positive displacement pipetter and adisposable pipette tip transfer 0.1-mL of the authentic sample intoa 25-mL vial.    11.2.2  Using an automatic pipetter and a disposable pipette tipdispense a 10-mL aliquot of solvent grade isopropyl alcohol (IPA)into the 25 mL vial.    11.2.3  Cap the vial and vortex the vial for ca. 10-15 seconds.    11.2.4  Let the sample extract stand for approximately 5minutes, allowing the solids to separate.    11.2.5  Using a 5-mL disposable plastic syringe remove 4 mL ofthe extract from the 25-mL vial.    11.2.6  Filter 4 mL of extract through a Teflon syringe filter(25-mm diameter, 0.45 m pore size), collecting the filtratein a labeled 4-mL vial.    11.2.7  Dispose of the PFTE syringe filter.    11.2.8  Using a black permanent marker, label a SepPak C18 cartridge with the sampleidentification.    11.2.9  Place the labeled Sep Pak C18cartridge onto the head of a SPE vacuum manifold.    11.2.10  Using a 5-mL disposable plastic syringe, draw upexactly 3-mL (air free) of isopropyl alcohol.    11.2.11  Attach the syringe tip to the top of the C18cartridge.    11.2.12  Condition the C18 cartridge with the 3-mL ofisopropyl alcohol by depressing the plunger slowly.    Note: Depress the plunger just to the point when no liquidremains in the syringe barrel. Do not force air through thecartridge. Collect the eluate in a waste vial.    11.2.13  Remove the syringe temporarily from the top of thecartridge, then remove the plunger, and finally reattach the syringebarrel to the top of the C18 cartridge.    11.2.14  Using automatic pipetters and disposable pipette tips,transfer 0.5 mL of the filtered extract into the syringe barrel,followed by a 3.0-mL transfer of isopropyl alcohol to the syringebarrel.    11.2.15  Insert the plunger and slowly depress it to pass onlythe extract and solvent through the preconditioned C18cartridge.    Note: Depress the plunger just to the point when no liquidremains in the syringe barrel. Do not force air through thecartridge. Collect the eluate in a waste vial.    11.2.16  Remove the syringe temporarily from the top of thecartridge, then remove the plunger, and finally reattach the syringebarrel to the top of the C18 cartridge.    11.2.17  Using an automatic pipetter and disposable pipette tip,transfer 2.0 mL of isopropyl alcohol to the syringe barrel.    11.2.18  Insert the plunger and slowly depress it to pass thesolvent through the C18 cartridge.    Note: Depress the plunger just to the point when no liquidremains in the syringe barrel. Do not force air through thecartridge. Collect the eluate in a waste vial.    11.2.19  Remove the syringe and labeled C18 cartridgefrom the top of the SPE vacuum manifold.    11.2.20  Prepare a reagent blank according to the proceduresoutlined in Section 9.5 of this appendix.    11.2.21  Prepare the necessary NAF reference blanks for eachtype of NAF encountered in the field samples according to theprocedures outlined in Section 9.6 of this appendix.    11.2.22  Prepare the positive control (1% crude oil equivalent)according to Section 9.6.2 of this appendix.    11.3  Reagent blank fluorescence testing.    11.3.1  Place the reagent blank cartridge in a black box, undera black light.    11.3.2  Determine the presence or absence of fluorescence forthe reagent blank cartridge. If fluorescence is detected in theblank, analysis of the samples is halted until the source ofcontamination is eliminated and a prepared reagent blank shows nofluorescence under a black light. All samples must be associatedwith an uncontaminated method blank before the results may bereported for regulatory compliance purposes.    11.4  Sample fluorescence testing.    11.4.1  Place the respective NAF reference blank (Section 9.6 ofthis appendix) onto the tray inside the black box.    11.4.2  Place the authentic field sample cartridge (derived fromthe same NAF as the NAF reference blank) onto the tray, adjacent andto the right of the NAF reference blank.    11.4.3  Turn on the black light.    11.4.4  Compare the fluorescence of the sample cartridge withthat of the negative control cartridge (NAF blank, Section 9.6.1 ofthis appendix) and positive control cartridge (1% crude oilequivalent, Section 9.6.2 of this appendix).    11.4.5  If the fluorescence of the sample cartridge is equal toor brighter than the positive control cartridge (1% crude oilequivalent, Section 9.6.2 of this appendix), the sample isconsidered contaminated. Otherwise, the sample is clean.12.0  Data Analysis and Calculations    Specific data analysis techniques and calculations are notperformed in this SOP.13.0  Method Performance    This method was validated through a single laboratory study,conducted with rigorous statistical experimental design andinterpretation (Reference 16.4).14.0  Pollution Prevention    14.1  The solvent used in this method poses little threat to theenvironment when recycled and managed properly.15.0  Waste Management    15.1  It is the laboratory's responsibility to comply with allFederal, State, and local regulations governing waste management,particularly the hazardous waste identification rules and landdisposal restriction, and to protect the air, water, and land byminimizing and controlling all releases from bench operations.Compliance with all sewage discharge permits and regulations is alsorequired.    15.2  All authentic samples (drilling fluids) failing thefluorescence test (indicated by the presence of fluorescence) shallbe retained and classified as contaminated samples. Treatment andultimate fate of these samples is not outlined in this SOP.    15.3  For further information on waste management, consult ``TheWaste Management Manual for Laboratory Personnel,'' and ``Less isBetter: Laboratory Chemical Management for Waste Reduction,'' bothavailable from the American Chemical Society's Department ofGovernment Relations and Science Policy, 1155 16th Street, NW,Washington, DC 20036.16.0  References    16.1  ``Carcinogen--Working with Carcinogens,'' Department ofHealth, Education, and Welfare, Public Health Service, Center forDisease Control, National Institute for Occupational Safety andHealth, Publication No. 77-206, August 1977.    16.2  ``OSHA Safety and Health Standards, General Industry,''(29 CFR 1910), Occupational Safety and Health Administration, OSHA2206 (Revised, January 1976).    16.3  ``Handbook of Analytical Quality Control in Water andWastewater Laboratories,'' USEPA, EMSL-Ci, Cincinnati, OH 45268,EPA-600/4-79-019, March 1979.    16.4  Report of the Laboratory Evaluation of Static Sheen TestReplacements--Reverse Phase Extraction (RPE) Method for DetectingOil Contamination in Synthetic Based Mud (SBM). October 1998.Available from API, 1220 L Street, NW, Washington, DC 20005-4070,202-682-8000.Appendix 7 to Subpart A of Part 435--API Recommended Practice 13B-21. Description    a. This procedure is specifically intended to measure the amountof non-aqueous drilling fluid (NAF) base fluid from cuttingsgenerated during a drilling operation. This procedure is a retorttest which measures all oily material (NAF base fluid) and waterreleased from a cuttings sample when heated[[Page 6910]]in a calibrated and properly operating ``Retort'' instrument.    b. In this retort test a known mass of cuttings is heated in theretort chamber to vaporize the liquids associated with the sample.The NAF base fluid and water vapors are then condensed, collected,and measured in a precision graduated receiver.    Note: Obtaining a representative sample requires specialattention to the details of sample handling (e.g., location, method,frequency). See Addendum A and B for minimum requirements forcollecting representative samples. Additional sampling procedures ina given area may be specified by the NPDES permit controllingauthority.2. Equipment    a. Retort instrument--The recommended retort instrument has a50-cm3 volume with an external heating jacket.    Retort Specifications:    1. Retort assembly--retort body, cup and lid.    (a) Material: 303 stainless steel or equivalent.    (b) Volume: Retort cup with lid.    Cup Volume: 50-cm3.    Precision: 0.25-cm3.    2. Condenser--capable of cooling the oil and water vapors belowtheir liquification temperature.    3. Heating jacket--nominal 350 watts.    4. Temperature control--capable of limiting temperature ofretort to at least 930  deg.F (500  deg.C) and enough to boil offall NAFs.    b. Liquid receiver (10-cm3, 20-cm3)--the10-cm3 and 20-cm3 receivers are speciallydesigned cylindrical glassware with rounded bottom to facilitatecleaning and funnel-shaped top to catch falling drops. Forcompliance monitoring under the NPDES program, the analyst shall usethe 10-cm3 liquid receiver with 0.1 ml graduations toachieve greater accuracy.    1. Receiver specifications:    Total volume: 10-cm3, 20-cm3.    Precision (0 to 100%): 0.05 cm3,0.05 cm3.    Outside diameter: 10-mm, 13-mm.    Wall thickness: 1.50.1mm, 1.20.1mm.    Frequency of graduation marks (0 to 100%): 0.10-cm3,0.10-cm3.    Calibration: To contain ``TC'' @ 20 deg.C.    Scale: cm3, cm3    2. Material--Pyrex or equivalent glass.    c. Toploading balance--capable of weighing 2000 g and precisionof at least 0.1 g. Unless motion is a problem, the analyst shall usean electronic balance. Where motion is a problem, the analyst mayuse a triple beam balance.    d. Fine steel wool (No. 000)--for packing retort body.    e. Thread sealant lubricant: high temperature lubricant, e.g.Never-Seez or equivalent.    f. Pipe cleaners--to clean condenser and retort stem.    g. Brush--to clean receivers.    h. Retort spatula--to clean retort cup.    i. Corkscrew--to remove spent steel wool.3. Procedure    a. Clean and dry the retort assembly and condenser.    b. Pack the retort body with steel wool.    c. Apply lubricant/sealant to threads of retort cup and retortstem.    d. Weigh and record the total mass of the retort cup, lid, andretort body with steel wool. This is mass (A), grams.    e. Collect a representative cuttings sample (see Note in Section1 of this appendix).    f. Partially fill the retort cup with cuttings and place the lidon the cup.    g. Screw the retort cup (with lid) onto the retort body, weighand record the total mass. This is mass (B), grams.    h. Attach the condenser. Place the retort assembly into theheating jacket.    i. Weigh and record the mass of the clean and dry liquidreceiver. This is mass (C), grams. Place the receiver belowcondenser outlet.    j. Turn on the retort. Allow it to run a minimum of 1 hour.    Note: If solids boil over into receiver, the test shall bererun. Pack the retort body with a greater amount of steel wool andrepeat the test.    k. Remove the liquid receiver. Allow it to cool. Record thevolume of water recovered. This is (V), cm\3\.    Note: If an emulsion interface is present between the oil andwater phases, heating the interface may break the emulsion. As asuggestion, remove the retort assembly from the heating jacket bygrasping the condenser. Carefully heat the receiver along theemulsion band by gently touching the receiver for short intervalswith the hot retort assembly. Avoid boiling the liquids. After theemulsion interface is broken, allow the liquid receiver to cool.Read the water volume at the lowest point of the meniscus.    l. Weigh and record the mass of the receiver and its liquidcontents (oil plus water). This is mass (D), grams.    m. Turn off the retort. Remove the retort assembly and condenserfrom the heating jacket and allow them to cool. Remove thecondenser.    n. Weigh and record the mass of the cooled retort assemblywithout the condenser. This is mass (E), grams.    o. Clean the retort assembly and condenser.4. Calculations    a. Calculate the mass of oil (NAF base fluid) from the cuttingsas follows:    1. Mass of the wet cuttings sample (Mw) equals themass of the retort assembly with the wet cuttings sample (B) minusthe mass of the empty retort assembly (A).Mw = B-A  [1]    2. Mass of the dry retorted cuttings (MD) equals themass of the cooled retort assembly (E) minus the mass of the emptyretort assembly (A).MD = E-A  [2]    3. Mass of the NAF base fluid (MBF) equals the massof the liquid receiver with its contents (D) minus the sum of themass of the dry receiver (C) and the mass of the water (V).MBF = D-(C + V)  [3]    Note: Assuming the density of water is 1 g/cm\3\, the volume ofwater is equivalent to the mass of the water.    b. Mass balance requirement:    The sum of MD, MBF, and V shall be within5% of the mass of the wet sample.(MD + MBF + V)/Mw = 0.95 to 1.05[4]    The procedure shall be repeated if this requirement is not met.    c. Reporting oil from cuttings:    1. Assume that all oil recovered is NAF base fluid.    2. The mass percent NAF base fluid retained on the cuttings(%BFi) for the sampled discharge ``i'' is equal to 100times the mass of the NAF base fluid (MBF) divided by themass of the wet cuttings sample (Mw).%BFi = (MBF/Mw)  x  100  [5]    Operators discharging small volume NAF-cuttings discharges whichdo not occur during a NAF-cuttings discharge sampling interval(i.e., displaced interfaces, accumulated solids in sand traps, pitclean-out solids, or centrifuge discharges while cutting mud weight)shall either: (a) Measure the mass percent NAF base fluid retainedon the cuttings (%BFSVD) for each small volume NAF-cuttings discharges; or (b) use a default value of 25% NAF basefluid retained on the cuttings.    3. The mass percent NAF base fluid retained on the cuttings isdetermined for all cuttings wastestreams and includes finesdischarges and any accumulated solids discharged [see Section 4.c.6of this appendix for procedures on measuring or estimating the masspercent NAF base fluid retained on the cuttings (%BF) for dualgradient drilling seafloor discharges performed to ensure properoperation of subsea pumps].    4. A mass NAF-cuttings discharge fraction (X, unitless) iscalculated for all NAF-cuttings, fines, or accumulated solidsdischarges every time a set of retorts is performed (see Section4.c.6 of this appendix for procedures on measuring or estimating themass NAF-cuttings discharge fraction (X) for dual gradient drillingseafloor discharges performed to ensure proper operation of subseapumps). The mass NAF-cuttings discharge fraction (X) combines themass of NAF-cuttings, fines, or accumulated solids discharged from aparticular discharge over a set period of time with the total massof NAF-cuttings, fines, or accumulated solids discharged into theocean during the same period of time (see Addendum A and B of thisappendix). The mass NAF-cuttings discharge fraction (X) for eachdischarge is calculated by direct measurement as:Xi = (Fi)/(G)  [6]where:Xi = Mass NAF-cuttings discharge fraction for NAF-cuttings, fines, or accumulated solids discharge ``i'', (unitless)Fi = Mass of NAF-cuttings discharged from NAF-cuttings,fines, or accumulated solids discharge ``i'' over a specified periodof time (see Addendum A and B of this appendix), (kg)G = Mass of all NAF-cuttings discharges into the ocean during thesame period of time as used to calculate Fi, (kg)    If an operator has more than one point of NAF-cuttingsdischarge, the mass faction (Xi) must be determined by:(a) Direct measurement (see Equation 6 of this[[Page 6911]]Appendix); (b) using the following default values of 0.85 and 0.15for the cuttings dryer (e.g., horizontal centrifuge, verticalcentrifuge, squeeze press, High-G linear shakers) and fines removalunit (e.g., decanting centrifuges, mud cleaners), respectively, whenthe operator is only discharging from the cuttings dryer and thefines removal unit; or (c) using direct measurement of``Fi'' (see Equation 6 of this Appendix) for fines andaccumulated solids, using Equation 6A of this Appendix to calculate``GEST'' for use as ``G'' in Equation 6 of this Appendix,and calculating the mass (kg) of NAF-cuttings discharged from thecuttings dryer (Fi) as the difference between the mass of``GEST'' calculated in Equation 6A of this appendix (kg)and the sum of all fines and accumulated solids mass directlymeasured (kg) (see Equation 6 of this Appendix).GEST = Estimated mass of all NAF-cuttings discharges intothe ocean during the same period of time as used to calculateFi (see Equation 6 of this Appendix), (kg)  [6A]where:GEST = Hole Volume (bbl)  x  (396.9 kg/bbl)  x  (1 + Z/100)Z = The base fluid retained on cuttings limitation or standard (%)which apply to the NAF being discharge (see Secs. 435.13. and435.15).Hole Volume (bbl) = [Cross-Section Area of NAF interval(in2)]  x  Average Rate of Penetration (feet/hr)  xperiod of time (min) used to calculate Fi (see Equation 6of this Appendix)  x  (1 hr/60 min)  x  (1 bbl/5.61 ft3)x  (1 ft/12 in)2Cross-Section Area of NAF interval (in2) = (3.14  x  [BitDiameter (in)]2)/4Bit Diameter (in) = Diameter of drilling bit for the NAF intervalproducing drilling cuttings during the same period of time as usedto calculate Fi (see Equation 6 of this Appendix)Average Rate of Penetration (feet/hr) = Arithmetic average of rateof penetration into the formation during the same period of time asused to calculate Fi (see Equation 6 of this Appendix)    Note: Operators with one NAF-cuttings discharge may set the massNAF-cuttings discharge fraction (Xi) equal to 1.0.    5. Each NAF-cuttings, fines, or accumulated solids discharge hasan associated mass percent NAF base fluid retained on cuttings value(%BF) and mass NAF-cuttings discharge fraction (X) each time a setof retorts is performed. A single total mass percent NAF base fluidretained on cuttings value (%BFT) is calculated everytime a set of retorts is performed. The single total mass percentNAF base fluid retained on cuttings value (%BFT) iscalculated as:%BFT,j = (Xi) x (%BFi)[7]where:%BFT,j = Total mass percent NAF base fluid retained oncuttings value for retort set ``j'' (unitless as percentage, %)Xi = Mass NAF-cuttings discharge fraction for NAF-cuttings, fines, or accumulated solids discharge ``i'', (unitless)%BFi = Mass percent NAF base fluid retained on thecuttings for NAF-cuttings, fines, or accumulated solids discharge``i'' , (unitless as percentage, %)    Note: Xi = 1.    Operators with one NAF-cuttings discharge may set%BFT,j equal to %BFi.    6. Operators performing dual gradient drilling operations mayrequire seafloor discharges of large cuttings (>\1/4\") to ensurethe proper operation of subsea pumps (e.g., electrical submersiblepumps). Operators performing dual gradient drilling operations whichlead to seafloor discharges of large cuttings for the properoperation of subsea pumps shall either: (a) Measure the mass percentNAF base fluid retained on cuttings value (%BF) and mass NAF-cuttings discharge fraction (X) for seafloor discharges each time aset of retorts is performed; (b) use the following set of defaultvalues, (%BF=14%; X=0.15); or (c) use a combination of (a) and (b)(e.g., use a default value for %BF and measure X).    Additionally, operators performing dual gradient drillingoperations which lead to seafloor discharges of large cuttings forthe proper operation of subsea pumps shall also perform thefollowing tasks:    (a) Use side scan sonar or shallow seismic to determine thepresence of high density chemosynthetic communities. Chemosyntheticcommunities are assemblages of tube worms, clams, mussels, andbacterial mats that occur at natural hydrocarbon seeps or vents,generally in water depths of 500 meters or deeper. Seafloordischarges of large cuttings for the proper operation of subseapumps shall not be permitted within 1000 feet of a high densitychemosynthetic community.    (b) Seafloor discharges of large cuttings for the properoperation of subsea pumps shall be visually monitored and documentedby a Remotely Operated Vehicle (ROV) within the tether limit(approximately 300 feet). The visual monitoring shall be conductedprior to each time the discharge point is relocated (cuttingsdischarge hose) and conducted along the same direction as thedischarge hose position. Near-seabed currents shall be obtained atthe time of the visual monitoring.    (c) Seafloor discharges of large cuttings for the properoperation of subsea pumps shall be directed within a 150 foot radiusof the wellbore.    7. The weighted mass ratio averaged over all NAF well sections(%BFwell) is the compliance value that is compared withthe ``maximum weighted mass ratio averaged over all NAF wellsections'' BAT discharge limitations (see the table in Sec. 435.13and footnote 5 of the table in Sec. 435.43) or the ``maximumweighted mass ratio averaged over all NAF well sections'' NSPSdischarge limitations (see the table in Sec. 435.15 and footnote 5of the table in Sec. 435.45). The weighted mass ratio averaged overall NAF well sections (%BFwell) is calculated as thearithmetic average of all total mass percent NAF base fluid retainedon cuttings values (%BFT) and is given by the followingexpression:%BFwell = [j=1 to j=n  (%BFT,j)]/n[8]where:%BFwell = Weighted mass ratio averaged over all NAF wellsections (unitless as percentage, %)%BFT,j = Total mass percent NAF base fluid retained oncuttings value for retort set ``j'' (unitless as percentage, %)n = Total number of retort sets performed over all NAF well sections(unitless)    Small volume NAF-cuttings discharges which do not occur during aNAF-cuttings discharge sampling interval (i.e., displacedinterfaces, accumulated solids in sand traps, pit clean-out solids,or centrifuge discharges while cutting mud weight) shall be massaveraged with the arithmetic average of all total mass percent NAFbase fluid retained on cuttings values (see Equation 8 of thisAppendix). An additional sampling interval shall be added to thecalculation of the weighted mass ratio averaged over all NAF wellsections (%BFwell). The mass fraction of the small volumeNAF-cuttings discharges (XSVD) will be determined bydividing the mass of the small volume NAF-cuttings discharges(FSVD) by the total mass of NAF-cuttings discharges forthe well drilling operation (GWELL + FSVD).XSVD = FSVD / (GWELL +FSVD)  [9]where:XSVD = mass fraction of the small volume NAF-cuttingsdischarges (unitless)FSVD = mass of the small volume NAF-cuttings discharges(kg)GWELL = mass of total NAF-cuttings from the well (kg)    The mass of small volume NAF-cuttings discharges(FSVD) shall be determined by multiplying the density ofthe small volume NAF-cuttings discharges (svd)times the volume of the small volume NAF-cuttings discharges(VSVD).FSVD = svd  x  VSVD  [10]where:FSVD = mass of small volume NAF-cuttings discharges (kg)svd = density of the small volume NAF-cuttingsdischarges (kg/bbl)VSVD = volume of the small volume NAF-cuttings discharges(bbl)    The density of the small volume NAF-cuttings discharges shall bemeasured. The volume of small volume discharges (VSVD)shall be either: (a) Be measured or (b) use default values of 10 bblof SBF for each interface loss and 75 bbl of SBM for pit cleanoutper well.    The total mass of NAF-cuttings discharges for the well(GWELL) shall be either: (a) Measured; or (b) calculatedby multiplying 1.0 plus the arithmetic average of all total masspercent NAF base fluid retained on cuttings values [see Equation 8of this Appendix] times the total hole volume (VWELL) forall NAF well sections times a default value for the density theformation of 2.5 g/cm3 (396.9 kg/bbl).[[Page 6912]][GRAPHIC] [TIFF OMITTED] TR22JA01.161where:GWELL = total mass of NAF-cuttings discharges for thewell (kg)[j = 1 to j = n 2(%BFTj)]/n = see Equation 8 ofthis Appendix (unitless as a percentage)VWELL = total hole volume (VWELL) for all NAFwell sections (bbl)    The total hole volume of NAF well sections (VWELL)will be calculated as:[GRAPHIC] [TIFF OMITTED] TR22JA01.170    For wells where small volume discharges associated with cuttingsare made, %BFWELL becomes:[GRAPHIC] [TIFF OMITTED] TR22JA01.171    Note: See Addendum A and B to determine the sampling frequencyto determine the total number of retort sets required for all NAFwell sections.    8. The total number of retort sets (n) is increased by 1 foreach sampling interval (see Section 2.4, Addendum A of thisappendix) when all NAF cuttings, fines, or accumulated solids forthat sampling interval are retained for no discharge. A zerodischarge interval shall be at least 500 feet up to a maximum ofthree per day. This action has the effect of setting the total masspercent NAF base fluid retained on cuttings value (%BFT)at zero for that NAF sampling interval when all NAF cuttings, fines,or accumulated solids are retained for no discharge.    9. Operators that elect to use the Best Management Practices(BMPs) for NAF-cuttings shall use the procedures outlined inAddendum B.Addendum A to Appendix 7 to Subpart A of Part 435--Sampling of CuttingsDischarge Streams for use with API Recommended Practice 13B-21.0  Sampling Locations    1.1  Each NAF-cuttings waste stream that discharges into theocean shall be sampled and analyzed as detailed in Appendix 7. NAF-cuttings discharges to the ocean may include discharges from primaryshakers, secondary shakers, cuttings dryer, fines removal unit,accumulated solids, and any other cuttings separation device whoseNAF-cuttings waste is discharged to the ocean. NAF-cuttingswastestreams not directly discharged to the ocean (e.g., NAF-cuttings generated from shake shakers and sent to a cuttings dryerfor additional processing) do not require sampling and analysis.    1.2  The collected samples shall be representative of each NAF-cuttings discharge. Operators shall conduct sampling to avoid theserious consequences of error (i.e., bias or inaccuracy). Operatorsshall collect NAF-cuttings samples near the point of origin andbefore the solids and liquid fractions of the stream have a chanceto separate from one another. For example, operators shall collectshale shaker NAF-cuttings samples at the point where NAF-cuttingsare coming off the shale shaker and not from a holding containerdownstream where separation of larger particles from the liquid cantake place.    1.3  Operators shall provide a simple schematic diagram of thesolids control system and sample locations to the NPDES permitcontrolling authority.2.0  Type of Sample and Sampling Frequency    2.1  Each NAF-cuttings, fines, or accumulated solids dischargehas an associated mass percent NAF base fluid retained on cuttingsvalue (%BF) and mass NAF-cuttings discharge fraction (X) for eachsampling interval (see Section 2.4 of this addendum). Operatorsshall collect a single discrete NAF-cuttings sample for each NAF-cuttings waste stream discharged to the ocean during every samplinginterval.    2.2  Operators shall use measured depth in feet from the Kellybushing when samples are collected.    2.3  The NAF-cuttings samples collected for the mass fractionanalysis (see Equation 6, Appendix 7 of Subpart A of this part)shall also be used for the retort analysis (see Equations 1-5,Appendix 7 of Subpart A of this part).    2.4  Operators shall collect and analyze at least one set ofNAF-cuttings samples per day while discharging. Operators engaged infast drilling (i.e., greater than 500 linear NAF feet advancement ofdrill bit per day) shall collect and analyze one set of NAF-cuttingssamples per 500 linear NAF feet of footage drilled. Operators arenot required to collect and analyze more than three sets of NAF-cuttings samples per day (i.e., three sampling intervals). Operatorsperforming zero discharge of all NAF-cuttings (i.e., all NAFcuttings, fines, or accumulated solids retained for no discharge)shall use the following periods to count sampling intervals: (1) Onesampling interval per day when drilling is less than 500 linear NAFfeet advancement of drill bit per day; and (2) one sampling intervalper 500 linear NAF feet of footage drilled with a maximum of threesampling intervals per day.    2.5  The operator shall measure the individual masses(Fi, kg) and sum total mass (G, kg) (see Equation 6,Appendix 7 of subpart A of this part) over a representative periodof time (e.g., 10 minutes) during steady-state conditions for eachsampling interval (see Section 2.4 of this addendum). The operatorshall ensure that all NAF-cuttings are capture for mass analysisduring the same sampling time period (e.g., 10 minutes) atapproximately the same time (i.e., all individual mass samplescollected within one hour of each other).    2.6  Operators using Best Management Practices (BMPs) to controlNAF-cuttings discharges shall follow the procedures in Addendum B toAppendix 7 of subpart A of 40 CFR 435.3.0  Sample Size and Handling    3.1  The volume of each sample depends on the volumetric flowrate (cm\3\/s) of the NAF-cuttings stream and the sampling timeperiod (e.g., 10 minutes). Consequently, different solids controlequipment units producing different NAF-cuttings waste streams atdifferent volumetric flow rates will produce different size samplesfor the same period of time. Operators shall use appropriately sizedsample containers for each NAF-cuttings waste stream to ensure noNAF-cuttings are spilled during sample collection. Operators shalluse the same time period (e.g., 10 minutes) to collect NAF-cuttingssamples from each NAF-cuttings waste stream. Each NAF-cuttingssample size shall be at least one gallon. Operators shall clearlymark each container to identify each NAF-cuttings sample.    3.2  Operators shall not decant, heat, wash, or towel the NAF-cuttings to remove NAF base fluid before mass and retort analysis.    3.3  Operators shall first calculate the mass of each NAF-cuttings sample and perform the mass ratio analysis (see Equation 6,Appendix 7 of subpart A of this part). Operators with only one NAF-cuttings discharge may skip this step (see Section 4.c.4, Appendix 7of subpart A of this part).    3.4  Operators shall homogenize (e.g., stirring, shaking) eachNAF-cuttings sample prior to placing a sub-sample into the retortcup. The bottom of the NAF-cuttings sample container shall beexamined to be sure that solids are not sticking to it.    3.5  Operators shall then calculate the NAF base fluid retainedon cuttings using the retort procedure (see Equations 1-5, Appendix7 of subpart A of this part). Operators shall start the retortanalyses no more than two hours after collecting the firstindividual mass sample for the sampling interval .    3.6  Operators shall not discharge any sample beforesuccessfully completing the mass and retort analyses [i.e., massbalance[[Page 6913]]requirements (see Section 4.b, Appendix 7 of subpart A of this part)are satisfied]. Operators shall immediately re-run the retortanalyses if the mass balance requirements (see Equation 4, Appendix7 of subpart A of this part) are not within a tolerance of 5% (seeSection 4.b, Equation 4, Appendix 7 of subpart A of this part).4.0  Calculations    4.1  Operators shall calculate a set of mass percent NAF basefluid retained on cuttings values (%BF) and mass NAF-cuttingsdischarge fractions (X) for each NAF-cuttings waste stream (seeSection 1.1 of this addendum) for each sampling interval (seeSection 2.4 of this addendum) using the procedures outlined inAppendix 7 of subpart A of this part.    4.2  Operators shall tabulate the following data for eachindividual NAF-cuttings sample: (1) Date and time of NAF-cuttingssample collection; (2) time period of NAF-cuttings sample collection(see Section 3.1 of this addendum); (3) mass and volume of each NAF-cuttings sample; (4) measured depth (feet) at NAF-cuttings samplecollection (see Section 2.2 of this addendum); (5) respective linearfeet of hole drilled represented by the NAF-cuttings sample (feet);and (6) the drill bit diameter (inches) used to generate the NAF-cuttings sample cuttings.    4.3  Operators shall calculate a single total mass percent NAFbase fluid retained on cuttings value (%BFT) for eachsampling interval (see Section 2.4 of this addendum) using theprocedures outlined in Appendix 7 of Subpart A of this part.    4.4  Operators shall tabulate the following data for each totalmass percent NAF base fluid retained on cuttings value(%BFT) for each NAF-cuttings sampling interval: (1) Dateand starting and stopping times of NAF-cuttings sample collectionand retort analyses; (2) measured depth of well (feet) at start ofNAF-cuttings sample collection (see Section 2.2 of this addendum);(3) respective linear feet of hole drilled represented by the NAF-cuttings sample (feet); (4) the drill bit diameter (inches) used togenerate the NAF-cuttings sample cuttings; and (5) annotation whenzero discharge of NAF-cuttings is performed.    4.5  Operators shall calculate the weighted mass ratio averagedover all NAF well sections (%BFwell) using the proceduresoutlined in Appendix 7 of Subpart A of this part.    4.6  Operators shall tabulate the following data for eachweighted mass ratio averaged over all NAF well sections(%BFwell) for each NAF well: (1) Starting and stoppingdates of NAF well sections; (2) measured depth (feet) of all NAFwell sections; (3) total number of sampling intervals (see Section2.4 and Section 2.6 of this addendum); (4) number of samplingintervals tabulated during any zero discharge operations; (5) totalvolume of zero discharged NAF-cuttings over entire NAF wellsections; and (6) identification of whether BMPs were employed (seeAddendum B of Appendix 7 of subpart A of this part).Addendum B to Appendix 7 to Subpart A of Part 435-- Best ManagementPractices (BMPs) for use with API Recommended Practice 13B-21.0  Overview of BMPs    1.1  Best Management Practices (BMPs) are inherently pollutionprevention practices. BMPs may include the universe of pollutionprevention encompassing production modifications, operationalchanges, material substitution, materials and water conservation,and other such measures. BMPs include methods to prevent toxic andhazardous pollutants from reaching receiving waters. Because BMPsare most effective when organized into a comprehensive facility BMPPlan, operators shall develop a BMP in accordance with therequirements in this addendum.    1.2  The BMP requirements contained in this appendix werecompiled from several Regional permits, an EPA guidance document(i.e., Guidance Document for Developing Best Management Practices(BMP)'' (EPA 833-B-93-004, U.S. EPA, 1993)), and draft industryBMPs. These common elements represent the appropriate mix of broaddirections needed to complete a BMP Plan along with specific taskscommon to all drilling operations.    1.3  Operators are not required to use BMPs if all NAF-cuttingsdischarges are monitored in accordance with Appendix 7 of Subpart Aof this part.2.0  BMP Plan Purpose and Objectives    2.1  Operators shall design the BMP Plan to prevent or minimizethe generation and the potential for the discharge of NAF from thefacility to the waters of the United States through normaloperations and ancillary activities. The operator shall establishspecific objectives for the control of NAF by conducting thefollowing evaluations.    2.2  The operator shall identify and document each NAF well thatuses BMPs before starting drilling operations and the anticipatedtotal feet to be drilled with NAF for that particular well.    2.3  Each facility component or system controlled through use ofBMPs shall be examined for its NAF-waste minimization opportunitiesand its potential for causing a discharge of NAF to waters of theUnited States due to equipment failure, improper operation, naturalphenomena (e.g., rain, snowfall).    2.4  For each NAF wastestream controlled through BMPs whereexperience indicates a reasonable potential for equipment failure(e.g., a tank overflow or leakage), natural condition (e.g.,precipitation), or other circumstances to result in NAF reachingsurface waters, the BMP Plan shall include a prediction of the totalquantity of NAF which could be discharged from the facility as aresult of each condition or circumstance.3.0  BMP Plan Requirements    3.1  The BMP Plan may reflect requirements within the pollutionprevention requirements required by the Minerals Management Service(see 30 CFR 250.300) or other Federal or State requirements andincorporate any part of such plans into the BMP Plan by reference.    3.2  The operator shall certify that its BMP Plan is complete,on-site, and available upon request to EPA or the NPDES Permitcontrolling authority. This certification shall identify the NPDESpermit number and be signed by an authorized representative of theoperator. This certification shall be kept with the BMP Plan. Fornew or modified NPDES permits, the certification shall be made nolater than the effective date of the new or modified permit. Forexisting NPDES permits, the certification shall be made within oneyear of permit issuance.    3.3  The BMP Plan shall:    3.3.1  Be documented in narrative form, and shall include anynecessary plot plans, drawings or maps, and shall be developed inaccordance with good engineering practices. At a minimum, the BMPPlan shall contain the planning, development and implementation, andevaluation/reevaluation components. Examples of these components arecontained in ``Guidance Document for Developing Best ManagementPractices (BMP)'' (EPA 833-B-93-004, U.S. EPA, 1993).    3.3.2  Include the following provisions concerning BMP Planreview.    3.3.2.1  Be reviewed by permittee's drilling engineer andoffshore installation manager (OIM) to ensure compliance with theBMP Plan purpose and objectives set forth in Section 2.0.    3.3.2.2  Include a statement that the review has been completedand that the BMP Plan fulfills the BMP Plan purpose and objectivesset forth in Section 2.0. This statement shall have dated signaturesfrom the permittee's drilling engineer and offshore installationmanager and any other individuals responsible for development andimplementation of the BMP Plan.    3.4  Address each component or system capable of generating orcausing a release of significant amounts of NAF and identifyspecific preventative or remedial measures to be implemented.4.0  BMP Plan Documentation    4.1  The operator shall maintain a copy of the BMP Plan andrelated documentation (e.g., training certifications, summary of themonitoring results, records of NAF-equipment spills, repairs, andmaintenance) at the facility and shall make the BMP Plan and relateddocumentation available to EPA or the NPDES Permit controllingauthority upon request.5.0  BMP Plan Modification    5.1  For those NAF wastestreams controlled through BMPs, theoperator shall amend the BMP Plan whenever there is a change in thefacility or in the operation of the facility which materiallyincreases the generation of those NAF-wastes or their release orpotential release to the receiving waters.    5.2  At a minimum the BMP Plan shall be reviewed once every fiveyears and amended within three months if warranted. Any such changesto the BMP Plan shall be consistent with the objectives and specificrequirements listed in this addendum. All changes in the BMP Planshall be reviewed by the permittee's drilling engineer and offshoreinstallation manager.[[Page 6914]]    5.3  At any time, if the BMP Plan proves to be ineffective inachieving the general objective of preventing and minimizing thegeneration of NAF-wastes and their release and potential release tothe receiving waters and/or the specific requirements in thisaddendum, the permit and/or the BMP Plan shall be subject tomodification to incorporate revised BMP requirements.6.0  Specific Pollution Prevention Requirements for NAF DischargesAssociated with Cuttings    6.1  The following specific pollution prevention activities arerequired in a BMP Plan when operators elect to control NAFdischarges associated with cuttings by a set of BMPs.    6.2  Establishing programs for identifying, documenting, andrepairing malfunctioning NAF equipment, tracking NAF equipmentrepairs, and training personnel to report and evaluatemalfunctioning NAF equipment.    6.3  Establishing operating and maintenance procedures for eachcomponent in the solids control system in a manner consistent withthe manufacturer's design criteria.    6.4  Using the most applicable spacers, flushes, pills, anddisplacement techniques in order to minimize contamination ofdrilling fluids when changing from water-based drilling fluids toNAF and vice versa.    6.5  A daily retort analysis shall be performed (in accordancewith Appendix 7 to subpart A of Part 435) during the first 0.33 Xfeet drilled with NAF where X is the anticipated total feet to bedrilled with NAF for that particular well. The retort analyses shallbe documented in the well retort log. The operators shall use thecalculation procedures detailed in Appendix 7 to subpart A of part435 (see Equations 1 through 8) to determine the arithmetic average(%BFwell) of the retort analyses taken during the first0.33 X feet drilled with NAF.    6.5.1  When the arithmetic average (%BFwell) of theretort analyses taken during the first 0.33 X feet drilled with NAFis less than or equal to the base fluid retained on cuttingslimitation or standard (see Secs. 435.13 and 435.15), retortmonitoring of cuttings may cease for that particular well. The sameBMPs and drilling fluid used during the first 0.33 X feet shall beused for all remaining NAF sections for that particular well.    6.5.2  When the arithmetic average (%BFwell) of theretort analyses taken during the first 0.33 X feet drilled with NAFis greater the base fluid retained on cuttings limitation orstandard (see Secs. 435.13 and 435.15), retort monitoring shallcontinue for the following (second) 0.33 X feet drilled with NAFwhere X is the anticipated total feet to be drilled with NAF forthat particular well. The retort analyses for the first and second0.33 X feet shall be documented in the well retort log.    6.5.2.1  When the arithmetic average (%BFwell) of theretort analyses taken during the first 0.66 X feet (i.e., retortanalyses taken from first and second 0.33 X feet) drilled with NAFis less than or equal to the base fluid retained on cuttingslimitation or standard (see Secs. 435.13 and 435.15), retortmonitoring of cuttings may cease for that particular well. The sameBMPs and drilling fluid used during the first 0.66 X feet shall beused for all remaining NAF sections for that particular well.    6.5.2.2  When the arithmetic average (%BFwell) of theretort analyses taken during the first 0.66 X feet (i.e., retortanalyses taken from first and second 0.33 X feet) drilled with NAFis greater than the base fluid retained on cuttings limitation orstandard (see Secs. 435.13 and 435.15), retort monitoring shallcontinue for all remaining NAF sections for that particular well.The retort analyses for all NAF sections shall be documented in thewell retort log.    6.5.3  When the arithmetic average (%BFwell) of theretort analyses taken over all NAF sections for the entire well isgreater that the base fluid retained on cuttings limitation orstandard (see Secs. 435.13 and 435.15), the operator is in violationof the base fluid retained on cuttings limitation or standard andshall submit notification of these monitoring values in accordancewith NPDES permit requirements. Additionally, the operator shall, aspart of the BMP Plan, initiate a reevaluation and modification tothe BMP Plan in conjunction with equipment vendors and/or industryspecialists.    6.5.4  The operator shall include retort monitoring data anddates of retort-monitored and non-retort-monitored NAF-cuttingsdischarges managed by BMPs in their NPDES permit reports.    6.6  Establishing mud pit and equipment cleaning methods in sucha way as to minimize the potential for building-up drill cuttings(including accumulated solids) in the active mud system and solidscontrol equipment system. These cleaning methods shall include butare not limited to the following procedures.    6.6.1  Ensuring proper operation and efficiency of mud pitagitation equipment.    6.6.2  Using mud gun lines during mixing operations to provideagitation in dead spaces.    6.6.3  Pumping drilling fluids off of drill cuttings (includingaccumulated solids) for use, recycle, or disposal before using washwater to dislodge solids.Appendix 8 to Subpart A of Part 435--Reference C16-C18 Internal Olefin Drilling Fluid Formulation    The reference C16-C18 internal olefindrilling fluid used to determine the drilling fluid sedimenttoxicity ratio and compliance with the BAT sediment toxicitydischarge limitation (see Sec. 435.13) and NSPS (see Sec. 435.15)shall be formulated to meet the specifications in Table 1 of thisappendix.    Drilling fluid sediment toxicity ratio = 4-day LC50of C16-C18 internal olefin drilling fluid/4-day LC50 of drilling fluid removed from cuttings at thesolids control equipment as determined by ASTM E1367-92[incorporated by reference and specified at Sec. 435.11(ee)] andsupplemented with the sediment preparation procedure (Appendix 3 ofsubpart A of this part).         Table 1.--Properties for Reference C16-C18 IOs SBF Used in Discharge Sediment Toxicity Testing----------------------------------------------------------------------------------------------------------------                                                                                          Reference C16-C18 IOsMud weight of SBF discharged with cuttings (pounds per gallon)   Reference C16-C18 IOs    SBF synthetic to water                                                                SBF (pounds per gallon)         ratio (%)----------------------------------------------------------------------------------------------------------------8.5-11........................................................                      9.0                    75/2511-14.........................................................                     11.5                    80/20>14...........................................................                     14.5                    85/15================================================================================================================Plastic Viscosity (PV), centipoise (cP).......................                    12-30Yield Point (YP), pounds/100 sq. ft...........................                    10-2010-second gel, pounds/100 sq. ft..............................                     8-1510-minute gel, pounds/100 sq. ft..............................                    12-30Electrical stability, V.......................................                     >300----------------------------------------------------------------------------------------------------------------Subpart D--Coastal Subcategory    8. Section 435.41 is amended by revising paragraphs (b) through(ff) and by adding paragraphs (gg) through (ii) to read as follows:Sec. 435.41  Special definitions.* * * * *    (b) Average of daily values for 30 consecutive days means theaverage of the daily values obtained during any 30 consecutive dayperiod.    (c) Base fluid means the continuous phase or suspending medium of adrilling fluid formulation.    (d) Base fluid retained on cuttings as applied to BAT effluentlimitations and NSPS refers to the American Petroleum InstituteRecommended Practice 13B-2[[Page 6915]]supplemented with the specifications, sampling methods, and averagingmethod for retention values provided in Appendix 7 of subpart A of thispart.    (e) Biodegradation rate as applied to BAT effluent limitations andNSPS for drilling fluids and drill cuttings refers to the ISO11734:1995 method: ``Water quality--Evaluation of the `ultimate'anaerobic biodegradability of organic compounds in digested sludge--Method by measurement of the biogas production (1995 edition)''(Available from the American National Standards Institute, 11 West 42ndStreet, 13th Floor, New York, NY 10036) supplemented with modificationsin Appendix 4 of subpart A of this part.    (f) Cook Inlet refers to coastal locations north of the linebetween Cape Douglas on the West and Port Chatham on the east.    (g) Daily values as applied to produced water effluent limitationsand NSPS means the daily measurements used to assess compliance withthe maximum for any one day.    (h) Deck drainage means any waste resulting from deck washings,spillage, rainwater, and runoff from gutters and drains including drippans and work areas within facilities subject to this Subpart.    (i) Development facility means any fixed or mobile structuresubject to this Subpart that is engaged in the drilling of productivewells.    (j) Dewatering effluent means wastewater from drilling fluids anddrill cuttings dewatering activities (including but not limited toreserve pits or other tanks or vessels, and chemical or mechanicaltreatment occurring during the drilling solids separation/recycle/disposal process).    (k) Diesel oil refers to the grade of distillate fuel oil, asspecified in the American Society for Testing and Materials StandardSpecification for Diesel Fuel Oils D975-91, that is typically used asthe continuous phase in conventional oil-based drilling fluids. Thisincorporation by reference was approved by the Director of the FederalRegister in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copiesmay be obtained from the American Society for Testing and Materials,1916 Race Street, Philadelphia, PA 19103. Copies may be inspected atthe Office of the Federal Register, 800 North Capitol Street, NW.,Suite 700, Washington, DC. A copy may also be inspected at EPA's WaterDocket, 401 M Street SW., Washington, DC 20460.    (l) Domestic waste means the materials discharged from sinks,showers, laundries, safety showers, eye-wash stations, hand-washstations, fish cleaning stations, and galleys located within facilitiessubject to this Subpart.    (m) Drill cuttings means the particles generated by drilling intosubsurface geologic formations and carried out from the wellbore withthe drilling fluid. Examples of drill cuttings include small pieces ofrock varying in size and texture from fine silt to gravel. Drillcuttings are generally generated from solids control equipment andsettle out and accumulate in quiescent areas in the solids controlequipment or other equipment processing drilling fluid (i.e.,accumulated solids).    (1) Wet drill cuttings means the unaltered drill cuttings andadhering drilling fluid and formation oil carried out from the wellborewith the drilling fluid.    (2) Dry drill cuttings means the residue remaining in the retortvessel after completing the retort procedure specified in Appendix 7 ofsubpart A of this part.    (n) Drilling fluid means the circulating fluid (mud) used in therotary drilling of wells to clean and condition the hole and tocounterbalance formation pressure. Classes of drilling fluids are:    (1) Water-based drilling fluid means the continuous phase andsuspending medium for solids is a water-miscible fluid, regardless ofthe presence of oil.    (2) Non-aqueous drilling fluid means the continuous phase andsuspending medium for solids is a water-immiscible fluid, such asoleaginous materials (e.g., mineral oil, enhanced mineral oil,paraffinic oil, C16-C18 internal olefins, andC8-C16 fatty acid/2-ethylhexyl esters).    (i) Oil-based means the continuous phase of the drilling fluidconsists of diesel oil, mineral oil, or some other oil, but contains nosynthetic material or enhanced mineral oil.    (ii) Enhanced mineral oil-based means the continuous phase of thedrilling fluid is enhanced mineral oil.    (iii) Synthetic-based means the continuous phase of the drillingfluid is a synthetic material or a combination of synthetic materials.    (o) Enhanced mineral oil as applied to enhanced mineral oil-baseddrilling fluid means a petroleum distillate which has been highlypurified and is distinguished from diesel oil and conventional mineraloil in having a lower polycyclic aromatic hydrocarbon (PAH) content.Typically, conventional mineral oils have a PAH content on the order of0.35 weight percent expressed as phenanthrene, whereas enhanced mineraloils typically have a PAH content of 0.001 or lower weight percent PAHexpressed as phenanthrene.    (p) Exploratory facility means any fixed or mobile structuresubject to this Subpart that is engaged in the drilling of wells todetermine the nature of potential hydrocarbon reservoirs.    (q) Formation oil means the oil from a producing formation which isdetected in the drilling fluid, as determined by the GC/MS complianceassurance method specified in Appendix 5 of subpart A of this part whenthe drilling fluid is analyzed before being shipped offshore, and asdetermined by the RPE method specified in Appendix 6 of subpart A ofthis part when the drilling fluid is analyzed at the offshore point ofdischarge. Detection of formation oil by the RPE method may beconfirmed by the GC/MS compliance assurance method, and the results ofthe GC/MS compliance assurance method shall supercede those of the RPEmethod.    (r) Garbage means all kinds of victual, domestic, and operationalwaste, excluding fresh fish and parts thereof, generated during thenormal operation of coastal oil and gas facility and liable to bedisposed of continuously or periodically, except dishwater, graywater,and those substances that are defined or listed in other Annexes toMARPOL 73/78. A copy of MARPOL may be inspected at EPA's Water Docket;401 M Street SW., Washington DC 20460.    (s) M9IM means those offshore facilities continuously manned bynine (9) or fewer persons or only intermittently manned by any numberof persons.    (t) M10 means those offshore facilities continuously manned by ten(10) or more persons.    (u) Maximum as applied to BAT effluent limitations and NSPS fordrilling fluids and drill cuttings means the maximum concentrationallowed as measured in any single sample of the barite fordetermination of cadmium and mercury content.    (v) Maximum for any one day as applied to BPT, BCT and BAT effluentlimitations and NSPS for oil and grease in produced water means themaximum concentration allowed as measured by the average of four grabsamples collected over a 24-hour period that are analyzed separately.Alternatively, for BAT and NSPS the maximum concentration allowed maybe determined on the basis of physical composition of the four grabsamples prior to a single analysis.    (w) Minimum as applied to BAT effluent limitations and NSPS fordrilling fluids and drill cuttings means the minimum 96-hourLC50 value allowed as measured in any single sample of thedischarged waste stream.[[Page 6916]]Minimum as applied to BPT and BCT effluent limitations and NSPS forsanitary wastes means the minimum concentration value allowed asmeasured in any single sample of the discharged waste stream.    (x)(1) New source means any facility or activity of thissubcategory that meets the definition of ``new source'' under 40 CFR122.2 and meets the criteria for determination of new sources under 40CFR 122.29(b) applied consistently with all of the followingdefinitions:    (i) Water area as used in ``site'' in 40 CFR 122.29 and 122.2 meansthe water area and water body floor beneath any exploratory,development, or production facility where such facility is conductingits exploratory, development or production activities.    (ii) Significant site preparation work as used in 40 CFR 122.29means the process of surveying, clearing or preparing an area of thewater body floor for the purpose of constructing or placing adevelopment or production facility on or over the site.    (2) ``New Source'' does not include facilities covered by anexisting NPDES permit immediately prior to the effective date of theseguidelines pending EPA issuance of a new source NPDES permit.    (y) No discharge of free oil means that waste streams may not bedischarged that contain free oil as evidenced by the monitoring methodspecified for that particular stream, e.g., deck drainage ormiscellaneous discharges cannot be discharged when they would cause afilm or sheen upon or discoloration of the surface of the receivingwater; drilling fluids or cuttings may not be discharged when they failthe static sheen test defined in Appendix 1 of subpart A of this part.    (z) Parameters that are regulated in this subpart and listed withapproved methods of analysis in Table 1B at 40 CFR 136.3 are defined asfollows:    (1) Cadmium means total cadmium.    (2) Chlorine means total residual chlorine.    (3) Mercury means total mercury.    (4) Oil and Grease means total recoverable oil and grease.    (aa) Produced sand means the slurried particles used in hydraulicfracturing, the accumulated formation sands and scales particlesgenerated during production. Produced sand also includes desanderdischarge from the produced water waste stream, and blowdown of thewater phase from the produced water treating system.    (bb) Produced water means the water (brine) brought up from thehydrocarbon-bearing strata during the extraction of oil and gas, andcan include formation water, injection water, and any chemicals addeddownhole or during the oil/water separation process.    (cc) Production facility means any fixed or mobile structuresubject to this subpart that is either engaged in well completion orused for active recovery of hydrocarbons from producing formations. Itincludes facilities that are engaged in hydrocarbon fluids separationeven if located separately from wellheads.    (dd) Sanitary waste means the human body waste discharged fromtoilets and urinals located within facilities subject to this subpart.    (ee) SPP toxicity as applied to BAT effluent limitations and NSPSfor drilling fluids and drill cuttings refers to the bioassay testprocedure presented in Appendix 2 of subpart A of this part.    (ff) Static sheen test means the standard test procedure that hasbeen developed for this industrial subcategory for the purpose ofdemonstrating compliance with the requirement of no discharge of freeoil. The methodology for performing the static sheen test is presentedin Appendix 1 of subpart A of this part.    (gg) Stock barite means the barite that was used to formulate adrilling fluid.    (hh) Synthetic material as applied to synthetic-based drillingfluid means material produced by the reaction of specific purifiedchemical feedstock, as opposed to the traditional base fluids such asdiesel and mineral oil which are derived from crude oil solely throughphysical separation processes. Physical separation processes includefractionation and distillation and/or minor chemical reactions such ascracking and hydro processing. Since they are synthesized by thereaction of purified compounds, synthetic materials suitable for use indrilling fluids are typically free of polycyclic aromatic hydrocarbons(PAH's) but are sometimes found to contain levels of PAH up to 0.001weight percent PAH expressed as phenanthrene. Internal olefins andvegetable esters are two examples of synthetic materials suitable foruse by the oil and gas extraction industry in formulating drillingfluids. Internal olefins are synthesized from the isomerization ofpurified straight-chain (linear) hydrocarbons such as C16-C18 linear alpha olefins. C16-C18linear alpha olefins are unsaturated hydrocarbons with the carbon tocarbon double bond in the terminal position. Internal olefins aretypically formed from heating linear alpha olefins with a catalyst. Thefeed material for synthetic linear alpha olefins is typically purifiedethylene. Vegetable esters are synthesized from the acid-catalyzedesterification of vegetable fatty acids with various alcohols. EPAlisted these two branches of synthetic fluid base materials to provideexamples, and EPA does not mean to exclude other synthetic materialsthat are either in current use or may be used in the future. Asynthetic-based drilling fluid may include a combination of syntheticmaterials.    (ii) Well completion fluids means salt solutions, weighted brines,polymers, and various additives used to prevent damage to the well boreduring operations which prepare the drilled well for hydrocarbonproduction.    (jj) Well treatment fluids means any fluid used to restore orimprove productivity by chemically or physically altering hydrocarbon-bearing strata after a well has been drilled.    (kk) Workover fluids means salt solutions, weighted brines,polymers, or other specialty additives used in a producing well toallow for maintenance, repair or abandonment procedures.    (ll) 96-hour LC50 means the concentration (parts permillion) or percent of the suspended particulate phase (SPP) from asample that is lethal to 50 percent of the test organisms exposed tothat concentration of the SPP after 96 hours of constant exposure.    9. In Sec. 435.42 the table is amended by removing the entries``Drilling fluids'' and ``Drill cuttings'' and by adding new entries(after ``Deck drainage'') for ``Water based'' and ``Non-aqueous'' toread as follows:Sec. 435.42  Effluent limitations guidelines representing the degree ofeffluent reduction attainable by the application of the bestpracticable control technology currently available (BPT).* * * * *[[Page 6917]]                                    BPT Effluent Limitations--Oil and Grease                                            [In milligrams per liter]----------------------------------------------------------------------------------------------------------------                                                                 Average of values for 30   Pollutant parameter waste source      Maximum for any 1 day    consecutive days shall     Residual chlorine                                                                        not exceed         minimum for any 1 day----------------------------------------------------------------------------------------------------------------       *                  *                   *                   *                  *                   *                                                          *Water-based:    Drilling fluids..................  ( \1\)..................  ( \1\)..................  NA    Drill Cuttings...................  ( \1\)..................  ( \1\)..................  NANon-aqueous:    Drilling fluids..................  No discharge............  No discharge............  NA    Drill Cuttings...................  ( \1\)..................  ( \1\)..................  NA       *                  *                   *                   *                  *                   *                                                       *----------------------------------------------------------------------------------------------------------------\1\ No discharge of free oil.* * * * *    10. In Sec. 435.43 the table is amended by revising entry (B) under``Drilling fluids, drill cuttings, and dewatering effluent'' and byrevising footnote 4 and adding footnote 5 to read as follows:Sec. 435.43  Effluent limitations guidelines representing the degree ofeffluent reduction attainable by the application of the best availabletechnology economically achievable (BAT).* * * * *                        BAT Effluent Limitations------------------------------------------------------------------------                                    Pollutant           BAT effluent         Waste source               parameter            limitation------------------------------------------------------------------------      *                  *                   *                   *                  *                   *                   *Drilling fluids, Drill cuttings, and Dewatering effluent: \1\      *                  *                   *                   *                  *                   *                   *(B) Cook Inlet:    Water-based drilling        SPP Toxicity.....  Minimum 96-hour LC50     fluids, drill cuttings,                        of the SPP Toxicity     and dewatering effluent.                       Test 4 shall be 3%                                                    by volume.                                Free oil.........  No discharge.\2\                                Diesel oil.......  No discharge.                                Mercury..........  1 mg/kg dry weight                                                    maximum in the stock                                                    barite.                                Cadmium..........  3 mg/kg dry weight                                                    maximum in the stock                                                    barite.    Non-aqueous drilling          ...............  No discharge.     fluids and dewatering     effluent.    Drill cuttings associated     ...............  No discharge.\5\     with non-aqueous drilling     fluids.      *                  *                   *                   *                 *                   *                   *------------------------------------------------------------------------\1\ 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.\2\ As determined by the static sheen test (see Appendix 1 of Subpart A  of this part).*                  *                   *                   *      *                   *                   *\4\ As determined by the suspended particulate phase (SPP) toxicity test  (see Appendix 2 of Subpart A of this part).\5\ When Cook Inlet operators cannot comply with this no discharge  requirement due to technical limitations (see Appendix 1 of Subpart D  of this part), Cook Inlet operators shall meet the same stock  limitations (C16-C18 internal olefin) and discharge limitations for  drill cuttings associated with non-aqueous drilling fluids for  operators in Offshore waters (see Sec.  435.13) in order to discharge  drill cuttings associated with non-aqueous drilling fluids.    11. In Sec. 435.44 the table is amended by revising the entry for``Cook Inlet'' under the entry for ``Drilling fluids and drill cuttingsand dewatering effluent'' to read as follows:Sec. 435.44  Effluent limitations guidelines representing the degree ofeffluent reduction attainable by the application of the bestconventional pollutant control technology (BCT).* * * * *[[Page 6918]]                        BCT Effluent Limitations------------------------------------------------------------------------                                  Pollutant         Waste source             parameter      BCT effluent limitation------------------------------------------------------------------------      *                  *                   *                   *                  *                   *                   *Drilling fluids, Drill cuttings, and Dewatering effluent: \1\      *                  *                   *                   *                  *                   *                   *Cook Inlet:    Water-based drilling       Free Oil.......  No discharge.\2\     fluids, drill cuttings,     and dewatering effluent.    Non-aqueous drilling         .............  No discharge.     fluids and dewatering     effluent.    Drill cuttings associated  Free Oil.......  No discharge.\2\     with non-aqueous     drilling fluids.------------------------------------------------------------------------\1\ 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.\2\ As determined by the static sheen test (see Appendix 1 of Subpart A  of this part).* * * * *    12. In Sec. 435.45 the table is amended by revising entry (B) under``Drilling fluids, drill cuttings, and dewatering effluent'' and byrevising footnote 4 and adding footnote 5 to read as follows:Sec. 435.45  Standards of performance for new sources (NSPS).* * * * *                 New Source Performance Standards (NSPS)------------------------------------------------------------------------                                    Pollutant         Waste Source               parameter               NSPS------------------------------------------------------------------------*                  *                  *                  *         *                  *                  *Drilling fluids, Drill cuttings, and Dewatering effluent: \1\*                  *                  *                  *         *                  *                  *(B) Cook Inlet:    Water-based drilling        SPP Toxicity.....  Minimum 96-hour LC50     fluids, drill cuttings,                        of the SPP Toxicity     and dewatering effluent.                       Test \4\ shall be 3%                                                    by volume.                                Free oil.........  No discharge.\2\                                Diesel oil.......  No discharge.                                Mercury..........  1 mg/kg dry weight                                                    maximum in the stock                                                    barite.                                Cadmium..........  3 mg/kg dry weight                                                    maximum in the stock                                                    barite.    Non-aqueous drilling          ...............  No discharge.     fluids and dewatering     effluent.    Drill cuttings associated     ...............  No discharge.\5\     with non-aqueous drilling     fluids.*                  *                  *                  *           *                  *                  *------------------------------------------------------------------------\1\ NSPS for dewatering effluent are applicable prospectively. NSPS 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.\2\ As determined by the static sheen test (see Appendix 1 of subpart A  of this part).*                  *                  *                  *     *                  *              *\4\ As determined by the suspended particulate phase (SPP) toxicity test  (see Appendix 2 of subpart A of this part).\5\ When Cook Inlet operators cannot comply with this no discharge  requirement due to technical limitations (see Appendix 1 of subpart D  of this part), Cook Inlet operators shall meet the same stock  limitations (C16-C18 internal olefin) and discharge limitations for  drill cuttings associated with non-aqueous drilling fluids for  operators in Offshore waters (see Sec.  435.15) in order to discharge  drill cuttings associated with non-aqueous drilling fluids.    13. Subpart D is amended by adding Appendix 1 as follows:Appendix 1 to Subpart D of Part 435--Procedure for Determining WhenCoastal Cook Inlet Operators Qualify for an Exemption from the ZeroDischarge Requirement for EMO-Cuttings and SBF-Cuttings in Coastal CookInlet, Alaska1.0  Scope and Application    This appendix is to be used to determine whether a Cook Inlet,Alaska, operator in Coastal waters (Coastal Cook Inlet operator)qualifies for the exemption to the zero discharge requirementestablished by 40 CFR 435.43 and 435.45 for drill cuttingsassociated with the following non-aqueous drilling fluids: enhancedmineral oil based drilling fluids (EMO-cuttings) and synthetic-baseddrilling fluids (SBF-cuttings). Coastal Cook Inlet operators areprohibited from discharging oil-based drilling fluids. This appendixis intended to define those situations under which technicallimitations[[Page 6919]]preclude Coastal Cook Inlet operators from complying with the zerodischarge requirement for EMO-cuttings and SBF-cuttings. CoastalCook Inlet operators that qualify for this exemption may beauthorized to discharge EMO-cuttings and SBF-cuttings subject to thelimitations applicable to operators in Offshore waters (see subpartA of this part).2.0  Method    2.1  Any Coastal Cook Inlet operator must achieve the zerodischarge limit for EMO-cuttings and SBF-cuttings unless itsuccessfully demonstrates that technical limitations prevent it frombeing able to dispose of its EMO-cuttings or SBF-cuttings throughon-site annular disposal, injection into a Class II undergroundinjection control (UIC) well, or onshore land application.    2.2  To successfully demonstrate that technical limitationsprevent it from being able to dispose of its EMO-cuttings or SBF-cuttings through on-site annular disposal, a Coastal Cook Inletoperator must show that it has been unable to establish formationinjection in nearby wells that were initially considered for annularor dedicated disposal of EMO-cuttings or SBF-cuttings or prove tothe satisfaction of the Alaska Oil and Gas Conservation Commission(AOGCC) that the EMO-cuttings or SBF-cuttings will be confined tothe formation disposal interval. This demonstration must include:    a. Documentation, including engineering analysis, that shows (1)an inability to establish formation injection (e.g., formation istoo tight), (2) an inability to confine EMO-cuttings or SBF-cuttingsin disposal formation (e.g., no confining zone or adequate barrierto confine wastes in formation), or (3) the occurrence of high riskemergency (e.g., mechanical failure of well, loss of ability toinject that risks loss of well which would cause significanteconomic harm or create a substantial risk to safety); and    b. A risk analysis of alternative disposal options, includingenvironmental assessment, human health and safety, and economicimpact, that shows discharge as the lowest risk option.    2.3  To successfully demonstrate that technical limitationsprevent it from being able to dispose of its EMO-cuttings or SBF-cuttings through injection into a Class II UIC well, a Coastal CookInlet operator must show that it has been unable to establishinjection into a Class II UIC well or prove to the satisfaction ofthe Alaska Oil and Gas Conservation Commission (AOGCC) that the EMO-cuttings or SBF-cuttings will be confined to the formation disposalinterval. This demonstration must include:    a. Documentation, including engineering analysis, that shows theinability to confine EMO-cuttings or SBF-cuttings in a Class II UICwell (e.g., no confining zone or adequate barrier to confine wastesin formation);    b. Documentation demonstrating that no Class II UIC well isaccessible (e.g., operator does not own, competitor will not allowinjection); and    c. A risk analysis of alternative disposal option, includingenvironmental assessment, human health and safety, and economicimpact, that shows discharge as the lowest risk option.    2.4  To successfully demonstrate that technical limitationsprevent it from being able to dispose of its EMO-cuttings or SBF-cuttings through land application, a Coastal Cook Inlet operatormust show that it has been unable to handle drilling waste ordispose of EMO-cuttings or SBF-cuttings at an appropriate landdisposal site. This demonstration must include:    a. Documentation of site restrictions that preclude landapplication (e.g., no land disposal sites available);    b. Documentation of the platform's lack of capacity for adequatestorage of EMO-cuttings or SBF-cuttings (e.g., limited storage orroom for cuttings transfer); or    c. Documentation of inability to transfer EMO-cuttings or SBF-cuttings from platform to land for disposal (e.g., extremely lowtides, high wave action).3.0  Procedure    3.1  Except as described in Section 3.2 of this appendix, aCoastal Cook Inlet operator believing that it qualifies for theexemption to the zero discharge requirement for EMO-cuttings or SBF-cuttings must apply for and obtain an individual NPDES permit priorto discharging EMO-cuttings or SBF-cuttings to waters of the UnitedStates.    3.2  Discharges occurring as the result a high risk emergency(e.g., mechanical failure of well, loss of ability to inject thatrisks loss of well which would cause significant economic harm orsafety) may be authorized by a general NPDES permit provided that:    a. The Coastal Cook Inlet operator satisfactorily demonstratesto EPA Region 10 the fulfillment of the other exemption requirementsdescribed in Section 2.0 of this appendix, or    b. The general permit allows for high risk emergency dischargesand provides Reporting Requirements to EPA Region 10 immediatelyupon commencing discharge.[FR Doc. 01-361 Filed 1-19-01; 8:45 am]BILLING CODE 6560-50-U