Federal Register Vol. No. 49 Wednesday, March 13, 1991 ...€¦ · 3/13/1991 · Federal Register...

Federal Register / Vol. 56, No. 49 / Wednesday, March 13, 1991 / Proposed Rules

ENVIRONMENTAL PROTECTIONENVIRONMENTAL PROTECTIONAGENCY

40 CFR Part 435

[FRL-3898-41

RIN 2040-AA12

Oil and Gas Extraction Point SourceCategory, Offshore Subcategory;Effluent Umitations Guidelines andNew Source Performance Standards

AGENCY: Environmental ProtectionAgency (EPA).ACTION: Proposed rule.

SUMMAIY: EPA is proposing regulationsunder the Clean Water Act to limiteffluent discharges to waters of theUnited States from offshore oil and gasextraction facilities. The purpose of thisproposal is to establish new sourceperformance standards (NSPS), besfavailable technology economicallyachievable (BAT), and bestconventional pollutant controltechnology (BCT) effluent limitationsguidelines for the offshore subcategoryof the oil and gas extraction pointsource category.

On November 26, 1990, EPA publishedan initial proposal and reproposal thatpresented the major regulatory optionsthat the Agency is considering forcontrol of drilling fluids, drill cuttings,produced water, deck drainage,produced sand, well treatment/workover fluids, and domestic andsanitary wastes. Today's noticedescribes the proposal In greater detailand sets forth additional technical,economic, environmental, and otherinformation relating to the establishmentof effluent guidelines and standards forthe offshore subcategory. Afterconsidering comments received inresponse to today's proposal and theNovember 26 proposal, EPA willpromulgate a final rule.

The Agency will schedule two publicworkshops to explain the proposedregulation. The Agency is inviting stateand EPA permit writers, industryrepresentatives and members of thegeneral public to attend and participatein these workshops. For information onthe dates and locations of theworkshops see the ADDRESSES sectionof today's notice.DATES: Comments must be received onor before April 12, 1991.ADDRESSES: Comments should be sentto Mr. Marvin B. Rubin, Office of Water,Industrial Technology Division (WH-552), Environmental Protection Agency,401 M Street SW., Washington, DC20460, (202) 382-7124.

The supporting information and allcomments on this proposal will beavailable for inspection and copying atthe EPA Public Information ReferenceUnit, room M2904 (Rear of EPAHeadquarters Library), 401 M StreetSW., Washington, DC, 9 a.m. to 4 p.m.,Monday through Friday, excludingFederal holidays. The EPA publicinformation regulation (40 CFR part 2)provides that a reasonable fee may becharged for copying. Technicalinformation on workshops and copies oftechnical documents may be obtainedfrom Mr. Marvin B. Rubin at the aboveaddress. The economic analysis reportmay be obtained from Ms. Ann Watkins,Economic Analysis Staff (WH-586), atthe above address, or call (202) 382-5387. The Regulatory Impact Analysis(RIA) may be obtained from Ms.Alexandra Tarnay, Assessment andWatershed Protection Division (WH-553), at the above address, or call (202)382-7046.FOR FURTHER INFORMATION CONTACT.Mr. Marvin B. Rubin at the aboveaddress, or call (202) 382-7124.SUPPLEMENTARY INFORMATION:

Organization of Today's NoticeI. Introduction.II. Summary of Legal Background.

A. Best Practicable Control TechnologyCurrently Available (BPT).

B. Best Available Technology EconomicallyAchievable (BAT).

C. Best Conventional Pollutant ConirolTechnology (BCT).

D. New Source Performance Standards(NSPS}.

I1. Overview of the Industry,A. Exploration, Development, and

Production.B. New and Existing Sources.C. Waste Streams.

IV. Prior EPA Regulations, Proposals andOther Notices, and General Permits.

A. EPA Rulemakings and General Permits.B. Relationship of Today's Proposal to the

1985 Proposal.1. Parts Changed from the 1985 Proposal.a. Section II of the 1985 Proposal: Scope of

Today's Rulemaking.b. Section V of the 1985 Proposal:

Overview of the Industry.c. Section XIII of the 1985 Proposal: Non-

Water Quality Environmental Impacts.d. Appendix 4 of the 1985 Proposal:

Regulatory Boundaries.e. Appendix 2 of the 1985 Proposal:

Analysis of Diesel Oil in Drilling Fluidsand Drill Cuttings Analytical Method.

2. Parts Not Changed from the 1985Proposal.

V. Industrial Sectors.A. Shallow/Deep Waters.B. Distance from Shore.

VI. Regulatory Definitions.A. Domestic Waste.B. Well Treatment, Completion. and

Workover Fluids.C. Produced Sand.

D. Development Facility and ProductionFacility.

VII. Data Gathering Efforts.A. Existing Information.B. New Studies.1. EPA Variability Study for Drilling Fluids

Toxicity Test.2. Performance of Granular Media and

Membrane Filtration Technologies onProduced Water.

C. Analytical Methods.1. Static Sheen Test.2. Diesel Oil Detection and Total Oil

Content-Proposed Method 1651.D. Radioactivity of Produced Water.E. Other Studies.

VIII. Waste Characterization.A. Produced Water and Drilling Wastes.B. Deck Drainage.C. Produced Sand.D. Well Treatment, Completion, and

Workover Fluids.E. Sanitary and Domestic Wastes.F. Other Minor Wastes.

IX. Parameters Selected for Regulation.A. Free Oil.B. Diesel Oil.C. Toxicity.D. Cadmium and Mercury.E. Oil Content.1. Drilling Fluids.2. Drill Cuttings.F. Oil and Grease.G. Residual Chlorine and Floating Solids.H. Foam.

X. Control and Treatment Technologies.A. Current Practice.1. Drilling Fluids.2. Drill Cuttings.3. Produced Water.4. Deck Drainage.5. Produced Sand.6. Well Treatment Fluids.7. Completion and Workover Fluids.8. Sanitary Wastes.9. Domestic Wastes:

B. Additional Technologies Considered.1. Drilling Fluids.a. Product Substitution.b. Zero Discharge.c. Clearinghouse Approach.d. Other Technologies.2. Drill Cuttings.3. Produced Water.a. Improved Performance of BPT

Technology.b. Filtration.c. Reinjection.d. Other Technologies.4. Deck Drainage, Domestic and Sanitary

Wastes.5. Produced 'Sand.6. Well Treatment, Completion and

Workover Fluids.XI. Best Practicable Technology.XII. Selection of Control and Treatment

Options for BCT.A. Methodology.B. Drilling Fluids and Cuttings.1. Options Considered.2. Alaskan Waters.3. Options Selection.C. Produced Water.1. Options Considered.2. Options Selection.

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D. Deck Drainage.E. Produced Sand.F. Well Treatment Completion and

Workover Fluids.C. Sanitary and Domestic Wastes.

XIII. Selection of Options for BAT.A. Drilling Fluids and Drill Cuttings.1. Options Considered.2. Options Selection.B. Produced Water.1. Options Considered.2. Options Selection.C. Deck Drainage.D. Produced Sand.E. Well Treatment, Completion and

Workover Fluids.F. Domestic and Sanitary Wastes.

XIV. Selection of Control and TreatmentOptions for NSPS.

XV. Revised Technology Costs andAssumptions.

A. Drilling Fluids and Cuttings.B. Produced Water.

XVI. Economic Analysis.A. Introduction.B. Costs and Economic Impacts.1. Basis of Analysis.2. Total Costs and Impacts of Proposed

Regulations.3. Economic Methodology.4. Costs and Impacts of Best Conventional

Pollutant Control Technology.5. Costs and Impacts of Best Available

Technology.a. Drilling Fluids and Drill Cuttings.b. Produced Waters.6. Costs and Impacts of New Source

Performance Standards.a. Drilling Fluids and Drill Cuttings.b. Produced Water.C. Cost-Effectiveness Analysis.D. Regulatory Flexibility Analysis.E. Paperwork Reduction Act.

XVIL Executive Order 12291.A. Produced Water.B. Drilling Fluids and Drill Cuttings.

XVIII. Non-Water Quality EnvironmentalImpacts and Other Factors.

A. Non-Water Quality EnvironmentalImpacts.

1. Energy Requirements and Air Emissions.2. Solid Waste Generation.3. Underground Injection of Produced

Water.B. Other Factors.

XIX. Solicitation of Comments.A. Industry Profile.B. Produced Water Treatment Costs.C. Drilling Fluids and Drill Cuttings

Treatment Costs.1. Discharge Volumes.2. Well Depths and Formation

Characteristics.3. Calculation of Discharge Volume Ratios.4. Valuation of Receiving Waters.D. Miscellaneous Discharges.E. Industry Profile Within Three Miles.F. Membrane Filtration Treatment

Technology for Produced Waters.G. Static Sheen Analytical Method.H. Radioactivity of Produced Water.1. Alaskan Waters.J. Treatment/Control Options for Drilling

Wastes.IC Cadmium Formation Contribution to

Drilling Wastes.

L Treatment/Control Options for ProducedWater.

M. Environmental Impact Analysis.XX. Variances and Modifications.

A. Stormwater Variance.XXI. OMB Review.

AppendicesA. Abbreviations, Acronyms and Other

Terms Used in Today's Notice.B. Major Documents Supporting the

Proposed Rule.C. Regulatory Boundaries.

I. Introduction

The purpose of this rulemaking is topropose standards of performance fornew sources and effluent limitationsguidelines for existing sourccs undersections 301, 304, 306, 307, and 501 of theClean Water Act for the OffshoreSubcategory of the Oil and GasExtraction Point Source Category. Theseregulations are also proposed inresponse to a Settlement Agreementapproved on April 5, 1990 in NRDC v.Reilly, D.D.C. No. 79-3442 (JHP) and inaccordance with EPA's EffluentGuidelines Plan under section 304(m) ofthe Clean Water Act (55 FR 80) (January2, 1990).

The proposed regulations would applyto discharges from offshore oil and gasextraction facilities, includingexploration, development andproduction operations that are seawardof the inner boundary of the territorialseas. The inner boundary of theterritorial seas is defined in section502(8) of the Clean Water Act as: "Theline of ordinary low water along thatportion of the coast which is in directcontact with the open sea and the linemarking the seaward limit of inlandwaters." The processes and operationswhich comprise the offshore oil and gasextraction subcategory (StandardIndustrial Classification (SIC) MajorGroup 13) are currently regulated under40 CFR part 435, subpart A. The existingeffluent limitations guidelines, whichwere issued on April 13, 1979 (44 FR22069), are based on the achievement ofbest practicable control technologycurrently available (BPT).

In general, BPT represents the averageof the best existing performances ofwell-known technologies and techniquesfor control of pollutants. BPT for theoffshore subcategory limits thedischarge of oil and grease in producedwater to a daily maximum of 72 mg/land a thirty-day average of 48 mg/l;prohibits the discharge of free oil indeck drainage, drilling fluids, drillcuttings, and well treatment fluids;requires a minimutm residual chlorinecontent of I mg/l in sanitary discharges;and prohibits the discharge of floatingsolids in sanitary and domestic wastes.

BPT limitations are not being changedby this proposal.

This rulemaking will establishregulations based on best availabletechnology economically achievable(BAT) that will result in reasonableprogress toward the goal of the CWA toeliminate the discharge of all pollutants.At a minimum, BAT represents the besteconomically achievable performance inthe industrial category or subcategory.This rulemaking also proposesrequirements based on bestconventional pollutant controltechnology (BCT). In addition, thisrulemaking proposes new sourceperformance standards (NSPS) based onthe best demonstrated controltechnology.

On August 26,1985, EPA proposedBAT, BCT, and NSPS for the offshore oiland gas industry (50 FR 34592). Thisproposal being issued today does notsupersede the 1985 proposal entirely but.rather, changes the proposal in certainareas. Some items proposed in 1985remain unchanged. In today's notice,EPA highlights the differences andsimilarities between today's proposaland the 1985 proposal.

Much data and information have beenacquired by EPA since the 1985 propos3lregarding waste characterization,treatment technologies, industrialpractices, industry profiles, analyticalmethods, environmental effects, costs.and economic impacts. Some of this newinformation regarding drilling wasteswas published in a Notice of DataAvailability (53 FR 41356) (October 21,1988). This new information has led EPAto develop additional regulatory optionsdifferent from those proposed in 1985.

On November 26 1990 the Agencypublished an initial proposal andreproposal (55 FR 49094) that presentedthe major BCT, BAT, and NSPSregulatory options under considerationfor control of drilling fluids, drillcuttings, produced water, deck drainage,produced sand, domestic and sanitarywastes, and well treatment, completion,and workover fluids. The optionspresented in that proposal are identicalto those presented today, with theexception that the November 26proposal stated that NSPS for sanitarywastes includes a prohibition on thedischarge of visible foam.

For this rulemaking, EPA is proposingBAT and NSPS effluent limitations forproduced waters equal to BPT forstructures located more than 4 milesfrom the inner boundary of theterritorial seas (shore). For structureslocated 4 miles or less from shore, EPAis proposing produced water effluentlimitations for oil and grease based on

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membrane filtration as an add-ontechnology to BPT. The limitations are 7mg/i monthly average and 13 mg/l dailymaximum nnt to be exceeded. Fordrilling fluids and drill cuttings, wellslocated more than 4 miles from shoreare subject to effluent limitations fortoxicity of 30,000 ppm (SPP basis),cadmium and mercury of 1 mg/kg eachin drilling fluids and drill cuttingsdischarges, as well as a requirement forno discharge of diesel oil and flee oil.For wells located 4 miles or less fromshore, zero discharge of drilling fluidsand drill cuttings is being proposed. Anexception to the limitations on drillingfluids and cuttings is being proposed forAlaska and is discussed later in sectionXII.

BAT and NSPS are also beingproposed for deck drainage; producedsand; treatment, completion, andworkover fluids; and domestic andsanitary wastes. These are collectivelyreferred to as the miscellaneous wastestreams. Zero discharge is beingproposed for the produced sand (solids)waste stream. Zero discharge oftreatment, completion, and workoverfluids is being proposed when theyresurface as a discrete slug. Otherwise,.if these fluids do not surface as adiscrete unit, then they would becommingled with and treated along withproduced waters. The Agency isproposing that deck drainage be subjectto the same limitations as producedwater during the production phase of theoil and gas extraction operation. Duringthe exploration and developmentphases, deck drainage will be subject tothe BPT limits prohibiting discharge offree oil. The Agency is not proposingBAT for domestic and sanitary wastesbecause there have been no toxic ornonconventional pollutants of concernidentified in these wastes. NSPS forsanitary wastes is being proposed asequal to BPT. NSPS for domestic wastesis proposed as equal to current permitrequirements prohibiting discharge offloating solids, plus the additionalrequirement for no visible discharge offoam.

BCT for produced waters is beingproposed equal to BPT. BCT for drillingfluids and drill cuttings is beingproposed equal to the zero discharge forstructures located 4 miles or less fromshore and BPT for structures greaterthan 4 miles from shore. The proposedBCT requirement for well treatment,completion, and workover fluids; deckdrainage and produced sand is nodischarge of free oil; for sanitary wastesBCT limitations are proposed controllingresidual chlorine at facilities with ten ormore personnel and no discharge of

floating solids for both sanitary wastesat facilities with less than ninepersonnel and for domestic wastes.

The Agency is collecting additionaldata concerning membranes which willbe noticed for public comment betweentoday's proposal and final rulemaking.In addition, the Agency solicits commenton this topic as part of this proposedrulemaking (see section XIX of today'snotice). Should the membranetechnology ultimately prove to be notdemonstrated for the purposes of thisregulation, EPA may promulgate BATand NSPS requirements for producedwater based on other technologiesgiving strong consideration to BPT asthe basis for BAT and NSPS since thecosts of alternative technologies arehigh. The level of pollutant removalswill also be considered in evaluatingthese technologies.

II. Summary of Legal Background

The regulations described in today'snotice are being developed under theauthority of sections 301, 304 (b), (c), and(e), 306, 307, and 501 of the Clean WaterAct (The Federal Water PollutionControl Act Amendments of 1972, asamended by the Clean Water Act of1977 and the Water Quality Act of 1987;33 U.S.C. 1311,1314 (b), (c), and (e), 1316,1317, and 1361; 86 Stat. 816, Pub. L. 92-500; 91 Stat. 1567, Pub. L 95-217; 101Stat. 7, Pub. L. 100-4) ("the Act").

The Clean Water Act establishes acomprehensive program to "restore andmaintain the chemical, physical, andbiological integrity of the Nation'swaters" (sec. 101(a)). To implement theAct, EPA is to issue technology basedeffluent limitations guidelines, newsource performance standards andpretreatment standards for industrialdischargers. The levels of controlassociated with these effluentlimitations guidelines and the newsource performance standards for directdischargers are summarized brieflybelow. Since no offshore facilitiescurrently discharge into municipal sewersystems, pretreatment standards are notincluded in this proposal and arereserved.

A. Best Practicable Control TechnologyCurrently Available (BPT)

BPT limitations are generally basedon the average of the best existingperformance by plants of various sizes,ages, and unit processes within thecategory or subcategory.

In establishing BPT limitations, EPAconsiders the total cost in relation to theage of equipment and facilities involved,the processes employed, processchanges required, engineering aspects ofthe control technologies and non-water

quality environmental impacts(including energy requirements). Thetotal cost of applying the technology isconsidered in relation to the effluentreduction benefits.

B. Best Available TechnologyEconomically Achievable (BAT)

BAT limitations, in general, representthe best existing performance in theindustrial subcategory or category. TheAct establishes BAT as a principalnational means of controlling the directdischarge of toxic and nonconventionalpollutants to navigable waters. Inarriving at BAT, the Agency considersthe age of the equipment and facilitiesinvolved, the process employed, theengineering aspects of the controltechnologies, process changes, the costsand economic impact of achieving sucheffluent reduction, non-water qualityenvironmental impacts (including energyrequirements), and such other factors asthe Administrator of EPA deemsappropriate. The Agency retainsconsiderable discretion in assigning theweight to be accorded these factors.

C. Best Conventional Pollutant ControlTechnology (BCT)

The 1977 Amendments added section301(b)(2)(E) to the Act establishing "bestconventional pollutant controltechnology" (BCT) for discharges ofconventional pollutants from existingindustrial point sources. Section304(a)(4) designated the following asconventional pollutants: Biochemicaloxygen demanding pollutants (BOD),total suspended solids (TSS), fecalcoliform, pH, and any additionalpollutants defined by the Administratoras conventional. The Administratordesignated oil and grease as anadditional conventional pollutant onJuly 30, 1979 (44 FR 44501).

BCT is not an additional limitation,but replaces BAT for the control of

* conventional pollutants. In addition toother factors specified in section304(b)(4)(B), the Act requires that BCTlimitations be established in light of atwo part "cost-reasonableness" test.American Paper Institute v. EPA, 660F.2d 954 (4th Cir. 1981). EPA firstpublished its methodology for carryingout the BCT analysis on August 19, 1979(44 FR 50372).

A revised methodology for the generaldevelopment of BCT limitations wasproposed on October 29, 1982 (47 FR49176), and became effective on August22, 1986 (51 FR 24974; July 9, 1986).

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D. New Source Performance StandardsINSPS)

NSPS are based on the best availabledemonstrated technology. New plantshave the opportunity to install the bestand most efficient production processesand wastewater treatment technologies.Therefore, Congress directed EPA toconsider the best demonstrated processchanges, in-plant controls, and end-of-process control and treatmenttechnologies that reduce pollution to themaximum extent feasible. In addition, inestablishing NSPS, EPA is required totake into consideration the cost ofachieving the effluent reduction and anynon-water quality environmental impactand energy requirements.IIl. Overview of the Industry

A. Exploration, Development, andProduction

The offshore subcategory of the oiland gas extraction point source categorycovers those structures involved inexploration, development, andproduction operations seaward of theinner boundary of the territorial seas, asdefined in Section 502 of the CleanWater Act.

Exploration and developmentactivities for the extraction of oil andgas include work necessary to locateand drill wells. Exploration (only)activities are those operations involvingthe drilling of wells to determine thepotential hydrocarbon reserves. Theseactivities are usually of short duration ata given site, involve a small number ofwells, and are generally conducted frommobile drilling units. (Only thoseexploratory activities with significantsite preparation are covered by today'sproposal. Significant site preparation, asdefined in the 1985 proposal, "shallmean the process of surveying, clearingand preparing an area of the ocean floorfor the purpose of constructing orplacing a development or productionfacility on or over the site.") The majorwaste streams from explorationactivities are drilling fluids and drillcuttings.

Development activities involve thedrilling of production wells once ahydrocarbon reserve has beenidentified. These operations, in contrastto exploration activities, usually involvea large number of wells and aretypically conducted from a fixedplatform. The waste streams of concerninclude drilling fluids, drill cuttings,deck drainage. and sanitary anddomestic wastes.

Production operations include allwork necessary to bring hydrocarbonreserves from the producing formationbeginning with the completion of each

well at the end of the developmentphase. The major waste stream fromproduction activities is the producedwater waste stream. Other wastestreams of concern include producedsand; deck drainage; sanitary anddomestic wastes; and well treatment,workover, and completion fluids.Produced water and sand originate withthe gas and/or oil product stream andare separated from the oil productduring the initial processing of theproduction stream. Well treatment,completion, and workover fluids arespecial fluids designed and used toprepare the well for production orenhance recovery of the oil productfrom, or prevent damage to, theformation.B. New and Existing Sources

EPA's industry profile estimates arebased upon information from the March1988 "Minerals Management ServicePlatform Inspection System, Complex/Structure Data Base." According to theMinerals Management Service (MMS)data, 2,260 structures currently produceoil and/or gas in the offshore waters ofthe United States. This estimateincludes all tracts leased offshore in theGulf of Mexico, California and Alaska.The Agency's estimate of existingstructures includes only those platformsthat are currently producing knownvolumes of a specific product (i.e., oil,gas or both). There are no structures inthe Atlantic, and the only platformsproducing oil in Alaskan waters whichare seaward of the inner boundary ofthe territorial seas are on gravel islandsand reinject their produced water. Thus,the Agency's estimate of existingproduction structures for Alaska is zero.

Structures located in state waters inthe Gulf of Mexico are not included inthis summary. However, the totalvolume of produced water beingdischarged and used as the basis forcosting the regulatory options is basedon industry estimates which include thestate water activities. The Agency hasattempted also to profile the number ofstructures in state "offshore" waters inthe Gulf of Mexico. Because of differentdefinitions contained in the state permitrecords, precise numbers of offshorestructures and wells have not beendetermined. The state offshore recordshave recorded permitted structuresunder three subcategories: Onshore (forthose structures whose well-head is onland but the bottomhole is offshore),coastal, and offshore. In the charts andmaps available from the NationalOceanic and AtmosphericAdministration (NOAA) and othersources, there is no indication of howmany wells there are per structure,

whether any of the wells are producingor what product may be produced.

In terms of new source developmentoperations, offshore drilling varies fromyear to year depending on such factorsas the price and supply of oil, theamount of state and federal leasing, andreservoir discoveries. In 1981, therewere almost 1500 wells drilled offshoreculminating the upward trend of the1970s. The average number of wellsdrilled during the 1972-1982 time periodwas 1100 wells/year. Drilling activityhas declined since 1982. Based on theMinerals Management Service's 30-yearregionalized forecasts the Agencyestimates that between 1986 and theyear 2000, assuming no regionalconstraints on development of offshoreoil and gas resources, there will be anaverage of 980 wells/year drilledoffshore nationwide (based on anaverage barrel of oil equivalent (BOE)price for the years 1986-2000 of $21/barrel). Of these 980 wells/year, 590wells/year will become producing wellsand the remaining 390 wells/year willbe dry holes.

EPA has also prepared an estimate ofdrilling activity which takes intoaccount the recent moratorium andrestricted leasing in the Pacific Oceanoff of California. On June 26, 1990, thePresident announced his decision toimplement a moratorium on oil and gasleasing and development in federalwaters off of California until the year2000. This "constrained" new wellprojection estimates that a total of 759wells/year will be drilled (with 455 ofthese going into production) between1986 and 2000 (also assuming $21/barrel(BOE)).

In addition to the offshore areas of theGulf of Mexico and the California coast,exploration is also occurring in areaswithin the Chukchi and Beaufort Seas ofAlaska, as well as in the AtlanticOcean, that may lead to new sourcedevelopment and production activities.

Estimates for production are alsobased on the constrained andunconstrained (restricted andunrestricted) scenarios. Theunconstrained profile estimates that 851platforms will be producing between1986 to 2000, while the constrainedscenario estimates 766 platforms.

C. Waste StreamsThe major wastewater sources from

the exploration and development phaseof the offshore oil and gas extractionindustry include the following:

" Drilling fluids." Drill cuttings." Sanitary wastes." Deck drainage.

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* Domestic wastes.Drilling fluids (typically termed "muds")and drill cuttings are the mostsignificant waste streams fromexploratory operations in terms both ofvolume and in toxic pollutant control.

The major wastewater sources fromthe production phase of the industryinclude the following

" Produced water.* Produced sand." Sanitary wastes.* Deck drainage." Domestic wastes." Well treatment fluids." Well completion and workover

fluids.Produced water is the most significant

waste stream for production based onits volume of discharge and quantity ofpollutants. For purposes of this proposal,deck drainage, sanitary wastes,domestic wastes, produced sand, andwell treatment, completion, andworkover fluids are all termed"miscellaneous wastes."

Produced water is brought up from thehydrocarbon-bearing strata along withproduced oil and gas, and can includeformation water, injection water, andany chemicals added downhole orduring the oil/water separation process.

Drilling fluids means any fluid sentdown th, Irillhole. This includes thosematerials used to maintain hydrostaticpressure control in the well, lubricatethe drill bit remove drill cuttings fromthe well, and stabilize the walls of thewell during drilling or workoveroperations. A water-based drilling fluidis the conventional drilling system inwhich water is the continuous phase.

Drill cuttings are the solids generatedby drilling into subsurface geologicformations, and are carried to thesurface by the drilling fluid system.

Deck drainage includes all wasteresulting from platform washings, deckwashings, rainwater, and runoff fromcurbs, gutters, and drains including drippans and work areas.

Well treatment wastes are spentfluids that result from acidizing andhydraulic fracturing operations toimprove oil recovery. Workover fluidsand completion fluids are low solidsfluids used to prepare a well forproduction, provide hydrostatic control,and/or prevent formation damage.

Produced sand consists of the slurriedparticles used in hydraulic fracturingand the accumulated formation sandsand other particles, and as scale, thatcan be generated during production.

Sanitary wastes originate from toilets.Domestic wastes originate from sinks,showers, laundries, and galleys.

Detailed discussions of the origins andcharacteristics of the wastewater

effluents from exploration, development,and production are presented in sectionVIII. The focus of this regulatory effort ison drilling fluids, drill cuttings, andproduced waters. Data gathering effortsand data analyses have been focused onthese waste streams due to theirvolumes and potential toxicity. Theinformation on the miscellaneouswastes is more limited. Their volumesare generally smaller, and in most caseseither sporadic or are part of the majorwaste streams. However, due to theconcern over the potential toxicity ofthese wastes, regulations formiscellaneous wastes are beingproposed in this notice as well.

In addition, other minor wastes aregenerated during the offshoreexploration development and productionactivities. These minor wastes areidentified and discussed in sectionVIII.F of today's notice; however, nolimits on these wastes are beingproposed since these types of dischargesare being sufficiently controlled by bestprofessional judgment (BPI) limits incurrent permits.

IV. Prior EPA Regulations, Proposalsand Other Notices, and General Permits

A. EPA Rulemakings and GeneralPermits

On September 15, 1975, EPApromulgated effluent limitationsguidelines for interim final BPT (40 FR42543) and proposed regulations for BATand NSPS (40 FR 42572) for the offshoresubcategory of the oil and gas extractionpoint source category. The Agencypromulgated final BPT regulations onApril 13, 1979 (44 FR 22069), but deferredaction on the BAT and NSPSregulations. Table I presents the 1979BPT limitations. These BPT limitationsare not being changed by this proposal.

TABLE 1 .- BPT EFFLUENT LIMITATIONS(PROMULGATED 1979)

Waste stream BPT effluent Limitationparamneter

Produced water.. -I and grease.. 72 mgl dailymaximum 4,mg/l 30-dayavg.

Drilling fluids ...... Free ....... No discharge.Drill cuttlngs..... Free ol ...... ...... No discharge,Well -eatment Free oil.....- No discharge.

fluids.Deck drainage ... Free oil ........... No discharge.Sanity-M10._..i Residual 1 mg/I (min.).

chlorWml.Sanitary-MtM Floating solids.-. No discharge.

NOTE: The free oil "no discharge" limitation Isimplemented by requiring no oil sheen to be presentupon discharge

The Natural Resources DefenseCouncil (NRDC filed suit on December

29, 1979 seeking an order to compel theAdministrator to promulgate final NSPSfor the offshore subcategory. Insettlement of the suit (NRDC v. Costle,D.D.C. No. 79-3442 (JHP)), the Agencyacknowledged the statutory requirementand agreed to take steps to issue suchstandards. However, because of thelength of time that had passed sinceproposal, EPA believed thatexamination of additional data and re-proposal were necessary. Consequently,the Agency withdrew the proposedNSPS on August 22, 1980 (45 FR 56115).The proposed BAT regulations werewithdrawn on March 19, 1981 (46 FR17567).

The Settlement Agreement wasrevised in April 1990. Under themodified agreement, EPA was topropose or repropose BAT and BCTeffluent limitations guidelines and newsource performance standards forproduced water, drilling fluids and drillcuttings, well treatment fluids, andproduced sand, as described at 50 FR34595 (August 26, 1985), by November16, 1990. The November 26, 1990proposal (which was signed onNovember 16) was an initial proposalthat was issued in satisfaction of thisprovision of the Settlement Agreement.EPA is to promulgate final guidelinesand standards covering these wastestreams by June 19, 1992.

EPA also was to determine byNovember 16, 1990 whether to proposeeffluent limitations guidelines and newsource performance standards coveringdeck drainage and domestic andsanitary wastes and, if it determined todo so, to promulgate final guidelines andstandards covering those waste streamsby June 30,1993. EPA has determinedthat it is appropriate to propose effluentlimitations guidelines and new sourceperformance standards covering deckdrainage and domestic and sanitarywastes. The Agency included suchproposals in the November 26 proposaland they are included in today's notice.

The Agency is using its best efforts tocomply with the promulgation datesestablished in the modified SettlementAgreement and currently expects tomeet them.

Ocean discharge criteria applicable tothis industry subcategory werepromulgated on October 3, 1980 (45 FR65942) under section 403(c) of the Act.These guidelines are to be used inmaking site-specific assessments of theimpacts of discharges. Section 403limitations are imposed through section402 National Pollutant DischargeElimination System (NPDESJ permits.Section 403 Is intended to preventunreasonable degradation of the marine

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environment and to authorize impositionof effluent limitations, including aprohibition of discharge, if necessary, toensure this goal.

On August 26, 1985 the Agencyproposed BAT, BCT, and NSPSregulations to control the discharge ofpollutants from the offshore oil and gasextraction subcategory (50 FR 34592)("1985 proposal"). The 1985 proposalalso included an amendment to the BPTdefinition of "no discharge of free oil."The waste streams covered by the 1985proposal were drilling fluids, drillcuttings, produced water, deck drainage,well treatment fluids, produced sand,and sanitary and domestic wastes. NoBAT effluent limitations guidelines wereproposed for the produced water wastestream; only NSPS and BCTrequirements for produced water wereproposed.

The key provisions of the 1985vrooosal were as follows:-Limit oil and grease to 59 mg/I daily

maximum and 48 mg/l monthlyaverage for produced water (NSPSonly) for all oil facilities located indeep water (Note: The definitions ofdeep and shallow water are describedin section V of today's notice), for alloil and gas facilities regardless oflocation or water depth, and for allexploratory facilities regardless oflocation or water depth. Thislimitation was based on the bestoperation of the BPT controltechnology (gas flotation). NSPS foroil facilities located in shallow waterprohibited the discharge of producedwater.

-Prohibit the discharge of free oil indrilling fluids, drill cuttings, deckdrainage, produced sand, and welltreatment fluids.

-Prohibit the discharge of diesel oil indetectable amounts in drill cuttingsand drilling fluids.

-Limit the acute toxicity of drilling fluiddischarges to a minimum 96-hour LC50of 3 percent (30,000 ppm) as measuredin the diluted suspended particulatephase (SPP).

-Limit the discharge of cadmium andmercury in drilling fluids to amaximum of 1 mg/kg each at the pointof discharge.The proposed BCT limitations

guidelines for produced water coveredthe conventional pollutant oil andgrease and were equal to the previouslypromulgated BPT effluent limitationsguidelines. For deck drainage, drillingfluids, drill cuttings, produced sand, andwell treatment fluids, proposed BCTlimitations prohibited the discharge offree oil. BCT effluent limitationsguidelines for additional conventional

pollutant parameters in deck drainage,drilling fluids, drill cuttings, producedsand, and well treatment fluids werereserved for future rulemakings.

On October 21, 1988, the Agencypublished a Notice of Data Availability(53 FR 41356) concerning thedevelopment of NSPS, BAT, and BCTregulations for the drilling fluids anddrill cuttings waste streams (the "1988notice"). The 1988 notice presentedsubstantial additional and revisedtechnical, cost, economic, andenvironmental effects information whichthe Agency collected after publication ofthe 1985 proposal. New information waspresented regarding the diesel oilprohibition and the toxicity limitation.New compliance costing and economicanalysis results were presented basedon new profile data and treatment andcontrol option development. The newcontrol technologies discussed werebased on thermal distillation, thermaloxidation, and solvent extraction.Performance data for these technologieswere also included. In addition,alternative requirements for limitationsof 5 mg/kg cadmium and 3 mg/kgmercury in the stock barite based on theuse of existing barite supplies, or at 2.5mg/kg cadmium and 1.5 mg/kg mercuryin the drilling fluids (whole fluid basis)were noticed for comment.

On January 9,1989, the Agencypublished a Correction to Notice of DataAvailability (54 FR 634) concerning theanalytical method for the measurementof oil content and diesel oil. The 1988notice had inadvertently published anincomplete version of that method.

As described in section I, onNovember 26, 1990 the Agencypublished a notice as an initial proposaland reproposal (55 FR 49094) thatpresented the major BCT, BAT, andNSPS regulatory options underconsideration for control of drillingfluids, drill cuttings, produced water,deck drainage, produced sand, domesticand sanitary wastes, and welltreatment, completion, and workoverfluids.

In addition. EPA has issued a series ofgeneral permits that set BAT and BCTlimitations applicable to sources in theoffshore subcategory on a BestProfessional Judgment (BPI) basis under402(a)(1) of the Clean Water Act. Seee.g., 51 FR 24897 (July 9. 1988) (Gulf ofMexico General Permit); 49 FR 23734(June 7,1984), modified 52 FR 30481(September 29, 1987) (Bering andBeaufort Seas General Permit); 50 FR23570 (June 4, 1985) (Norton SoundGeneral Permit); 51 FR 35400 (October 3,1986) (Cook Inlet/Gulf of AlaskaGeneral Permit); 53 FR 37840 (September20, 1988), modified 54 FR 39574

(September 27,1989) (Beaufort Sea H/Chukchi Sea General Permit). Wherepertinent, today's notice discusses themajor provisions of these generalpermits in relation to the effluentguidelines and standards beingproposed. The rulemaking record for thisproposal includes copies of the mostsignificant Federal Register noticesproposing these general permits andissuing them in final form.

The Gulf of Mexico General Permitwas challenged by industry and anenvironmental group. Natural ResourcesDefense Council v. EPA, 863 F.2d 1420(9th Cir. 1988). The Bering and BeaufortSeas General Permit was the subject ofindustry challenge. American PetroleumInstitute v. EPA, 787 F.2d 965 (5th Cir.1986); later opinion following partialremand, 858 F.2d 261, (5th Cir. 1988);clarified and rehearing denied, 864 F.2d1156 (5th Cir. 1989). Copies of thesedecisions are also included in therulemaking record for this proposal.

B. Relationship of Today's Proposal tothe 1985 Proposal

The proposal being issued today doesnot supercede the 1985 proposal entirely,but rather changes the proposal incertain areas. Below is a discussion ofthe parts of the 1985 proposal thatremain the same and the parts that arebeing changed. Reasons for the changesare discussed in the appropriatepreamble sections as indicated.

1. Parts Changed from the 1985 Proposal

New data and information gatheredsince the 1985 proposal have led theAgency to consider and develop newtreatment and control options for theoffshore oil and gas waste discharges.New information regarding datagathering and analytical methods isoutlined in section VII. New treatmentperformance data are presented insection X. The new treatment andcontrol options developed as a result ofthis new information are presented insections XH-XIV. Also included in thesesections are a discussion of the 1985options and how they differ from thecurrent proposals. The revised costs andeconomic analyses performed on thesenew options are summarized in sectionsXV and XVI. Other sections of the 1985proposal that have been changed arelisted below.

a. Section II of the 1985 Proposal:Scope of Today's Rulemaking. In 1985,no BAT limitations were proposed forproduced water. Today's notice isproposing BAT and NSPS effluentlimitations for produced water for oiland grease as an indicator pollutant.The limitations being proposed today

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are based on membrane filtration andset limits on oil and grease at 7 mg/Imonthly average and 13 mg/I dailymaximum not to be exceeded.

For drilling fluids, BAT and NSPSdischarge limitations were proposed in1985 for all drilling structures. Thisreproposal of BAT and NSPS isequivalent to the 1985 proposeddischarge limitations for thosestructures located outside of 4 milesfrom the inner boundary of theterritorial seas (shore). For wells located4 miles or less from shore, zerodischarge is proposed in today's notice.

For drill cuttings, the 1985 BAT andNSPS proposal included a prohibition onthe discharge of diesel oil and free oilfor all structures. Today's notice isproposing the same limitations for drillcuttings as for drilling fluids.

The 1985 BAT and NSPS proposalincluded a prohibition on the dischargeof free oil for deck drainage, producedsand, and well treatment fluids. For BATand NSPS, today's notice is proposing:(1) That deck drainage be subject to thesame limitations as produced waterduring production operations and torequirements equal to the current BPTlimits during the drilling operationsbefore any wells on a given structure areput into production; (2) that zerodischarge be required for producedsand; and (3) that for those welltreatment, completion, and workoverfluids that resurface as a discrete slug,zero discharge be required for the slugand a 100 barrel buffer on both sides ofthe slug. For those treatment,completion, and workover fluids thatcannot be segregated from the producedwater, the produced waters limitationswould apply. In the case of acidworkover fluids which resurface as aslug, neutralization (pH control) andapplication of the produced waterlimitations would be required. As in the1985 proposal, no BAT requirements fordomestic wastes or sanitary wastes arebeing proposed. NSPS for sanitarywastes were proposed in 1985 as equalto BPT. NSPS for domestic wastes wasproposed in 1985 to prohibit thedischarge of floating solids. Today'snotice today proposes BPT, plus arequirement for no visible foam, asNSPS for domestic wastes. ProposedNSPS for sanitary wastes is identical tothe 1985 proposal.

As in 1985, today's notice proposesBCT for produced water as being equalto BPT limitations on oil and grease.BCT limitations proposed in today'snotice for deck drainage and welltreatment, completion and workoverfluids are identical to the 1985 proposedlimitations equal to the BPT prohibitionon the discharge of free oil. BCT for

drilling fluids and drill cuttings wasproposed in 1985 as being equal to BPT.In today's notice, BCT for drilling fluidsand drill cuttings is proposed as zerodischarge for structures located withinfour miles from shore and BPT for thosestructures at distances greater than fourmiles from shore. In 1985, proposed BCTfor produced sand prohibited thedischarge of free oil. As proposed intoday's notice, BCT limitations wouldrequire zero discharge of produced sand.Today's proposed BCT limitations forsanitary wastes are identical to the 1985notice and set BCT equal to BPT.Today's notice also proposes BCTlimitations for domestic wastesprohibiting the discharge of floatingsolids.

b. Section V of the 1985 Proposal-Overview of the Industry. The location,size, and number of platforms, as wellas the status of the oil and gas industryhas been updated. New profileinformation is included in today'sproposal in section III.

c. Section XIII of the 1985 Proposal:Non- Water Quality EnvironmentalImpacts. Non-water qualityenvironmental impact analyses on thenew options EPA developed for thisrulemaking have had significantinfluence on the selection of preferredoptions for proposal. Section XVIII oftoday's proposal presents a discussionof the non-water quality environmentalimpacts associated with the newoptions.

d. Appendix 4 of the 1985Proposal:Regulatory Boundaries. This appendixlists regulatory boundaries associatedwith the shallow water classificationproposed in 1985. The boundaries asproposed have not changed, only theapplicability of this classification. The1985 proposal states that this appendixis applicable to shallow productionstructures subject to a zero dischargerequirement only. Today's notice deletesthis statement so as not to limit theapplicability of the shallowclassification to zero dischargerequirements. This change is included inappendix C of today's notice.

e. Appendix 2 of the 1985 Proposal:Analysis of Diesel Oil in Drilling Fluidsand Drill Cuttings Analytical Method.Changes to this method were presentedin appendix A of the 1988 Notice ofAvailability. These changes were aresult of experience obtained during theDiesel Pill Monitoring Program. Anincomplete version of the analyticalmethod was published in the 1988notice. A Federal Register notice waspublished later which contained thecorrect version (54 FR 634, Jan. 9,1989).

2. Parts Not Changed from the 1985Proposal

While the data acquired andtreatment and control options for theoffshore oil and gas industry aredifferent in the current proposal, manyitems proposed in 1985 remain the same.These items, are not included in thisproposal. Rather, those items that havenot changed since 1985 are now subjectto promulgation along with the itemsbeing proposed in today's notice. Thoseitems proposed in 1985 that are notbeing affected by this reproposal arelisted below.

a. Section IX of the 1985 proposalIndustry Subcategorization.

b. Section Xl of the 1985 proposal.Selection of Control and TreatmentOptions where it concerns the toxicitylimitation of 30,000 ppm in thesuspended particulate phase for drillingfluids.

c. Section XI.B of the 1985 proposal.The proposed amendment to the BPTdefinition of "no discharge of free oil".

d. Section XIV of the 1985 proposal.Definition of "new source."

e. Section XV of the 1985 proposal.Best Management Practices.

f Section XVI of the 1985 proposal.Upset and Bypass Provisions.

g. Section XVII of the 1985 proposal.Variances and Modifications, except fora new discussion on Stormwater Eventsincluded in section XX of today'sproposal.

h. Section XVIII of the 1985 proposal.Relationship to NPDES Permits.

i. Appendix 1 of the 1985proposedregulation. Static Sheen Test.

j. Appendix 3 of the 1985 proposedregulation. Drilling Fluids Toxicity Testanalytical method.

V. Industrial Sectors

A. Shallow/Deep Waters

One method used in today's notice(and in the previous 1985 proposal)divided the industry into two sectors:Those in shallow waters and those indeep waters. The Agency proposeddepth limits in order to allow for anoption of onshore reinjection ofproduced water from those structureslocated in shallow water. The Agencyfound that in shallower waters a highpercentage of the existing productionplatforms pipe produced waters to shorefor treatment rather than treatingproduced waters on the platform. TheAgency has also determined that thecost of drilling and equipping reinjectionwells on land is less than drillingreinjection wells at the platform.

In the 1985 proposal, the Agencyproposed variable depth limits that

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defined "shallow" for different offshoreareas which were based on bathymetricfeatures and industry practice forproduced water treatment andreinjection onshore. This proposedmethod of dividing the industry has notchanged since 1985 but is discussed intoday's notice for the reader'sinformation.

Through the compilation of data fromindustry the following water depthswere proposed to be shallow water:

Gulf of Mexico: Industry dataindicated that 52 percent of all theprojected new sources in 15 meters orless of offshore waters would pipeproduced water to shore. The Agencybelieved the same percentage ofplatforms in water depths of 20 metersor less could pipe to shore and reinject.

Atlantic: The water depth of 20 meterswas proposed as shallow for this regionsince there was no historic data forproduction.

California: It was determined that 60percent of the active productionplatforms located in water depths of 50meters or less piped to shore fortreatment while only 8 percent of thestructures in depths greater than 50meters piped to shore for treatment.Based on this information, a depth of 50

meters or less was proposed as shallowwater in California.

Alaska: It was assumed that southernAlaska bathymetry (ocean depth) wassimilar to California's bathymetry, so awater depth of 50 meters or less wasproposed to be shallow. The southernAlaska region includes the Bristol Bay,Aleutian Island Chain. Cook Inlet. andthe Gulf of Alaska. For other parts ofAlaska the Agency proposed shallowwater to be of a depth of 20 meters orless in the Norton Sound and 10 metersor less in the Beaufort Sea. The waterdepths in the North were proposed to beless than the 50 meters for southernAlaska because the harsher climates inthe more northern region made piping toshore for treatment less probable.

For determination of water depth,appendix 4, "Regulatory Boundaries," ofthe 1985 proposed regulations (andappendix C of today's notice) referencednautical charts or bathymetric mapsavailable from the National Oceanic andAtmospheric Administration. The waterdepth of the structure was defined to bebased on the proposed location of thestructure's well slot or produced waterdischarge point.

The shallow/deep water grouping wasconsidered in 1985 only for the

production phase of the industry. Thisdistinction was evaluated for certainzero discharge options based onreinjection of produced water. Today'scurrent reproposal includes the sameshallow/deep water classification forproduced waters; in addition, thoseclassifications also apply to drillingfluids and drill cuttings. As discussedlater in section XII. a zero dischargeoption for drilling wastes is beingconsidered for today's proposal. Thetechnology basis for a zero dischargerequirement for drilling wastes isbarging to shore for disposal. In additionto requiring zero discharge for allstructures, EPA considered requiringzero discharge only for those new wellsdrilled in shallow water in order tominimize the non-water qualityenvironmental impacts from barging andland disposal of these wastes.

Table 2 presents the number ofexisting producing structures bygeographic region, production type, andwater depth and shows that 99 percentof the existing offshore structures are inthe Gulf of Mexico. Shallow waterstructures account for approximately 58percent of existing structures.

TABLE 2.-NUMBER OF EXISTING PRODUCING STRUCTURES BY GEOGRAPHIC REGION, PRODUCTION TYPE, AND WATER DEPTH

Shallow Water Deep Water

Region Oil Oil aTotal Totaland Gas Oil Oil Gas Total all

sl- only and only deepon 'gas owgas

GUN.-_ .... ............................................................................................................ ........................... 126 497 676 1,299 35 471 428 934 2.233Pacific ....................................................... .................. .... . ... 0 10 0 10 0 16 1 17 27

faska _ ............................................................................................................. 0 0 0 0 0 0 0 0 0Atlantic _ ... .. ..................................................... ........ ........... 0 0 0 0 0 0 0 0 0

Totals ... _........ .. ... ................................................................................................... 126 507 676 1,309 35 487 429 951 2.260

The definition of shallow depth foruse with new well drilling is the same asthe definition used in the 1985 proposalsfor production activities. Table 3presents the estimate of the number ofnew wells to be drilled annually bygeographic region and water depth(based on projections for the years 1986-2000, at $21/barrel). This shows that agreater percentage of the drilling isexpected for new wells in deep watersthan in shallow waters (approximately71 percent).

TABLE 3.-ESTIMATE OF THE NUMBER OF

NEW WELL DRILLINGS PER YEAR BY

GEOGRAPHIC REGION AND WATER

DEPTH

11986 to 2000: 980 wellslyear will be drilled (60structures/year) 590 Producing Wells; 390 dryholes]

Shal-Region low Deep Totalwater

Gulf of Mexico ................. 265 450 715Pacific .............................. 10 227 237Alaska ... .............. 9 3 12Atlantic ........... ............... 0 16 16

Totals .......................... 264 696 980

B. Distance From Shore

In addition to those options whichdivided the industry by water depth.

EPA evaluated regulatory options whichgrouped the industry based on distanceand a well or structure from shore. Thisevaluation showed that the non-waterquality environmental impactsassociated with the zero dischargeoptions for drilling wastes warrantedfurther investigation and/orconsideration of adopting differentregulatory approaches for differentportions of the offshore industry.

The impacts of concern are the fuelrequirements and air emissions resultingfrom the barging of solid wastes to shorefor disposal. Also, EPA was concernedwith the long-term available on-landdisposal capacity to support the zerodischarge options. Thus, EPAinvestigated regulating the industry in amanner which would mitigate these non-water quality environmental impacts.

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EPA evaluated a breakdown ofstructure location based on distance (inmiles) from shore instead of depth ofwell. The distances evaluated were 4, 6,and 8 miles from shore. As a matter ofconsistency, these distances offshorewere evaluated for produced waters aswell as drilling fluids and drill cuttings.EPA also attempted to evaluate adistance of 3 miles from shore since thedelineation between state and federalleased water areas for the purpose of oiland gas extraction provides a well-defined separation point. However, dueto the problems in identifying existingoffshore production facilities from thestate data bases and the NOAA charts(as previously discussed in section fI.B),an accurate count of facilities at 3 milesor less from shore could not beestimated. For the 4, 6, and 8 miledistances, MMS empirical data and

projections were a basis for straight lineextrapolations for distances at 3 milesand less for existing new sources. TheAgency still considers the 3 miledelineation as a viable option and mayuse this in the final rule if accurateinformation on the number of existingproduction facilities and new sourceprojections can be obtained for thesewaters.

EPA determined in its analysis ofregulatory options that the use of a 4mile category is preferable to the otherdistances evaluated (6 and 8 miles)because either the further distancesfrom shore (8 miles or greater) do notreduce non-water quality environmentalimpacts sufficiently, or the differencebetween the pollutant removals at 6miles from those at 4 miles are notsignificant. The 4 mile option is theAgency's preferred option based on

distance. However, the Agency willconsider setting the final rule ondistances other than 4 miles with thereceipt of additional state watersinformation on the number of existingstructures and new well drillingprojections.

Table 4 presents the number ofexisting producing structures bygeographic region and production typeaccording to the 4 mile cutoff.Approximately 208 structures are 4miles or closer to shore. These representapproximately 9 percent of the total.This same percentage of structures,although not necessarily the samestructures, would be equivalent toregulating the drilling and productionactivities at a water depth of 6.3 metersin the Gulf of Mexico.

TABLE 4.-EXISTING PRODUCING STRUCTURES ACCORDING TO DISTANCE FROM SHORE

Less than or equal to 4 miles Greater than 4 miles

Region Oil O Gas Sub- Per- Oil OlI Gas Sub. Per. Totalonly ga only total cent only and only total cent

Gulf ................................. .. . . . ........ ............ 50 63 84 197 9 111 905 1,020 2,036 91 2,233Pacific ... ... ............................. ................. ....... .................. .......... 0 11 0 11 41 0 15 1 16 69 27Alaska ............. ; .................................................................................. . .... 0 0 0 0 0 0 0 0 0 0 0Atlantic ................... ................................. ... 0 0 0 0 0 0 0 0 0 0 0

Totals ........... ............... . ......................... 50 74 84 208 0 111 920 1,021 2,052 0 2,260

Table 5 presents the estimate of thenumber of new well drillings annuallyby geographic region according to the 4mile cutoff (for the years 1986-2000 at$21/barrel]. As can be seen by the table,approximately 16 percent of theestimated 980 new wells will be inwaters 4 miles or less from shore.

TABLE 5. Estimate of New Well DrillingsPer Year According to Distance fromShore "Unconstrained Development"

Less than GreaterRegion or equal to than 4 Total

4 miles miles

Gulf....... 72 643 715Pacific (off

California 1) 71 166 237Alaska ................ 9 3 12Atlantic .............. 0 16 16

Total .......................... .9............................. 980

This projection assumes no moratorium or re.stricted leasing off the coast of California.

This estimate is based'on assumptionscontained in the MMS Table 4projections which do not take intoaccount the recent moratorium andrestricted leasing in the Pacific offCalifornia. A more "constrained"

projection of new wells based on theseconditions gives approximately 759 newwells drilled annually (for the years1986-2000 at $21/barrel (BOE)). Table 6shows projections on a regional basisfor this constrained scenario andestimates approximately 11 percent ofthe new wells in waters 4 miles or lessfrom shore.

TABLE 6. Estimate of New Well DrillingsPer Year According to Distance fromShore "Constrained Development"

Less than GreaterRegion or equal to than 4 Total

4 miles miles

Gulf ...................... 72 643 715Pacific (off

California) ........ 71 32 32Alaska .................. 9 3 12Atlantic ................ 0 0 0

Total ............. . . ....................... 759

VL Regulatory Definitions

A. Domestic Waste

The August 26, 1985 proposal definesdomestic waste as wastewater resultingfrom laundries, galleys, showers, etc. In

today's proposal, other examples ofdomestic wastes are added for thepurpose of clarity. These include wastesfrom safety shower and eye washstations, hand wash stations, and fishcleaning stations. This clarification ofthe proposed definition does not changethe regulation or its economic impact.

B. Well Treatment, Completion, andWorkover Fluids

The 1985 proposal defines welltreatment fluids as "those fluids used instimulating a hydrocarbon bearingformation or in completing a well for oiland gas production, and drilling fluidsused in re-working a well to increase orrestore productivity."

EPA is proposing to change thisdefinition of well treatment fluids tomake it similar to the definition beingproposed in the coastal drilling permitsfor Texas and Louisiana by EPA'sRegion VI. This new definition makes adistinction between well treatmentfluids, completion fluids, and workoverfluids. The following definitions arebeing proposed in today's notice:

Well Treatment Fluids: "Any fluid used torestore or improve productivity by chemicallyor physically altering hydrocarbon-bearing

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strata after a well has been drilled." Thesefluids move into the formation and return tothe surface as a slug with the producedwater. Stimulation fluids include substancessu'h as acids, solvents and propping agents.

Well Completion Fluids: "Salt solutions,weighted brines, polymers and variousadditives used to prevent damage to the wellbore during operations which prepare thedrilled weU for hydrocarbon production."These fluids move into the formation andreturn to the surface as a slug with theproduced water.

Workover Fluids: "Salt solutions,weighted brines, polymers, or otherspecialty additives used in a producingwell to allow safe repair andmaintenance or abandonmentprocedures." High solids drilling fluidsused during workover operations are notconsidered workover fluids bydefinition. Packer fluids--low solidsfluids between the packer, productionstring, and well casing-are consideredto be workover fluids.

The definitions above distinguishtreatment, completion, and workoverfluids from drilling fluids and each otherbased on clear descriptions of form andfunction. Drilling fluids remaining in thewellbore during logging, casing, andcementing operations or duringtemporary abandonment of the well arenot considered completion fluids andare regulated by drilling fluidsrequirements.

Both high and low solids drilling fluidsused during workover operations are notconsidered workover fluids and mustalso meet drilling fluids effluentlimitations.

Production operations are defined as"operations including work necessary tobring hydrocarbon reserves from theproducing formation beginning with thecompletion of each well in thedevelopment phase;" thus, treatment,completion, and workover fluids, asdefined above, are considered part ofthe production phase. If these fluids donot come back up as a discrete slug,they will either remain In the hole, ordiffuse within the well's formation fluidsand resurface as part of the producedwater.

C. Produced Sand

Sand is obtained with the fluids fromthe formation during the productionprocess. This sand, termed "producedsand," is defined (1985 proposal) as"slurried particles used in hydraulicfracturing and the accumulatedformation sands and scale particlesgenerated during production." The sandis separated out from the producedwater, washed with either water orsolvent, and is either dischargedoverboard with the produced waterwaste stream or is stored in 55 gallon

drums and transported to shore fordisposaL

EPA is proposing to make thisdefinition more specific to include"desander discharge from the producedwater waste stream and blowdown ofthe water phase from the producedwater treating system." Thus, for theoptions considered for this proposal, thedefinition of produced sand is beingmodified to include the followingsentence:

Produced sand also includes desanderdischarge from the produced water wastestream and blowdown of the water phasefrom the produced water treating system.

D. Development Facility and ProductionFacility

EPA is proposing to change the 1985proposal definitions of "developmentfacility" and "production facility" tomore accurately reflect the wastestreams that occur during these phasesof the industry. The definition ofdevelopment facility is being changed tocover only the drilling portion of theoperation. Thus, the major wastestreams associated with this phase aredrilling fluids and cuttings.

The definition of production facility isbeing proposed to include thecompletion phase of the operation aswell as actual hydrocarbon extraction.The major waste stream associated withthis phase is produced water. Since welltreatment and completion fluidsresurface (if they surface at all) alongwith the produced waters, EPA believesit appropriate to associate welltreatment and completion with theproduction phase.VII. Data Gathering Efforts

A. Existing InformationIn October 1988, the Agency published

a Notice of Data Availability (53 FR41356) which presented new technical,economic, and environmentalinformation relating to the developmentof BAT and NSPS effluent guidelineslimitations for the drilling fluid and drillcuttings waste streams. This newinformation was submitted to theAgency in public comments in theresponse to the 1985 proposal. Thenotice was organized in two parts. Part 1of the notice discussed key issuessurrounding the drilling fluids toxicitylimitation, the proposed toxicity testmethod, the prohibition on the dischargeof drilling fluids containing diesel oiladditives, a re-evaluation of industrycompliance costs, an economic impactassessment of the revised cost estimatesand environmental impacts of thedischarge of cadmium and mercury in.drilling fluid waste streams. It also

presented two variations on the August1985 proposed regulatory approachrelated to the mercury and cadmiumlimitations in the whole drilling fluidsand stock barite used in the drillingfluids.

Part 2 of the notice discussedinformation gathered on new treatmenttechnologies for controlling the oilcontent of drilling wastes. Data on theperformance and cost of thermaldistillation/oxidation and solventextraction technologies for treatingdrilling fluids and drill cuttings werepresented for public review andcomment. This Information was beingconsidered for the development of an oilcontent limitation on drilling wastestreams. In addition, an analyticalmethod for determining diesel oil and oilcontent was included for comment.

B. New Studies

Since the 1988 notice, additionalstudies were conducted in response toconcerns over various aspects of thisrulemaking. Such concerns include: Thevariability of the test method used tomeasure toxicity of drilling fluids anddrill cuttings, additional technologiesavailable for produced water treatment,procedures for the static sheen test,radioactivity associated with producedwaters, and non-water qualityenvironmental impacts associated withvarious treatment and control options.The evaluation of non-water qualityenvironmental impacts including solidwaste disposal, air emissions and fuelrequirements are discussed separatelyin section XVIII of today's notice. Asummary of new information acquired isgiven below.

1. EPA Variability Study for DrillingFluids Toxicity Test

The 1985 offshore oil and gas proposalincluded a limitation on the toxicity ofdischarged drilling fluids. The toxicitylimit is expressed as the concentrationof the suspended particulate phase (SPP)from a sample of drilling fluid thatwould be lethal to 50 percent of aparticular species exposed to thatconcentration of the SPP, i.e., the LC50of the discharge. The species used in thetoxicity test is Mysidopsis bahia,otherwise called mysid shrimp. TheAgency proposed a toxicity limitation of39,000 ppm (SPP) based on the toxicityof the most toxic of eight generic drillingfluids that were in general use at thetime of proposal. In addition, permitwriters have set this limit as their bestprofessional judgment of BAT. It iscurrently included in the general permitfor oil and gas activities on the outercontinental shelf of the Gulf of Mexico.

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several individual offshore oil and gaspermits for California, and in Alaska.

As part of the evaluation of methodsunder section 304(h) of the Clean WaterAct and as a response to comments fromthe 1985 offshore oil and gas proposal,the Agency has recently conducted astudy of the variation in results from thetoxicity test for drilling fluids. The studywas conducted in two phases.

In Phase I, each lab was required toconduct one toxicity test on a sub-sample of generic drilling fluid #3 (limemud). The participating labs included 2Agency labs and 28 contract labs. The

contract labs included all commercial,academic, and industry labs known tothe Agency that claimed to haveexperience with some form of toxicitytesting and were willing to participate.The Agency knows of over 100commercial, academic, and industrylabs that are potentially capable ofconducting the required test.

In Phase II, each lab was required toconduct two toxicity tests on sub-samples of generic drilling fluid #8(lignosulfonate freshwater mud) and twotoxicity tests on sub-samples of genericdrilling fluid #8 with 3 percent mineral

oil. Contract labs were selected atrandom from those contract labs thatdemonstrated the ability to conduct thetoxicity test at a competitive price.

A summary of the study results ispresented in table 7. The "selected" labsin the summary for generic fluid #3 wereincluded because a review of the rawlab reports indicated that they correctlyfollowed the test protocol they receivedas part of the study. The primarysummary statistics included in the tableare the average toxicity (LC50), standarddeviation (SD], prediction intervals, andthe coefficient of variation (CV).

Table 7.-PRELIMINARY RESULTS FROM THE VARIABILITY STUDY OF THE DRILLING FLUIDS

No.ofoAverage SDrilling fluid Responses labso LC5O S c

I labs I (percent) I (percent) (percent)

Comlined within- and between-lab variationGeneric Fluid #3 ................................................ . ...................... l All ............................................................................... 28 25.6 12.0 47.1

I Selected .................................................................... 16 22.6 5.96 26.4Generic Fluid #8 .......................................... . All .............................................................................. . 9 50.9 19.4 38.1Generic Fluid #8 (3% Oil) All ............................................................................. 9 0.27 0.36 133.9

Drilling fluid, upper Responses No. of labs Average LC5 o (percent) Interval

With n-lab variationGeneric Fluid #8........................................All ........ ... . 59.9 104 20.5 26.6 7&2Generic Fluid #8 (3% Oil) ...................... All ............................... 9 0.27 0.20 72.0 +0.0 0.73

NoTEs:LCSO calculated using Probit Analysis by Maximum Ukelihood with optimization for control mortality."Average LG50" Is the average of the average LC50 for each lab.Standard Deviation (SD) for combined within- and between-lab variation Is the square root of the sum of mean squares for withlnlab variation plus the sum of

mean sauares for between lab vanation. SD for within-lab variation Is the square root of the sum of squares for within-lab variation.Coefficient of Vanation (CV) is SD/Average LC50.Prediction Interval is for within-process variation from labs that have demonstrated the ability to conduct EPA's toxicity test.

The average LC50 was slightly higher(less toxic) than expected for the sampleof generic drilling fluid #3 and for thesample of drilling fluid #8. However, theaverage LC50 reported for drilling fluid#8 with 3 percent mineral oil was lower(more toxic) than expected. It isimportant to note that each of theseaverages is based on a sub-sample froma single well-mixed sample of drillingfluid. Hence, the variation found in thisstudy is related only to within- andbetween-lab variation and any averageresult applies only to that one sample ofdrilling fluids. Generalizations toaverage levels for other batches of thesame generic drilling fluid or the samegeneric drilling fluid with mineral oil arenot supported by these data.

The standard deviations (SD) reportedin Table 7 indicate the magnitude ofvariation found in lab results for aparticular drilling fluid system. Becauseonly one test per lab was conducted onthe sample of generic drilling fluid #3 itis not possible to estimate within-labvariation for that sample. In order to

provide comparable statistics, combinedwithin- and between-lab standarddeviations are presented for all samplestested in the study. However, theAgency is primarily interested inestimates of within-lab variation sothese estimates are presented forgeneric drilling fluid #8 and genericdrilling fluid #8 with 3 percent mineraloil. Estimates of within-lab variationfrom competent labs quantifies thenatural variability inherent in themeasurement process while between labestimates of variability quantifies labbias. Lab bias describes the situationwhen all results of a particular lab areconsistently above or below the multi-lab average result. The Agency believesthat between lab variation is caused byconsistent lab practices that can bemodified through learning fromexperience. Additionally, an hypothesisthat lower LC50s are linked to lowerstandard deviations is suggested bytable 7 and the Agency is consideringfurther statistical analysis of thisrelationship.

Prediction intervals for within-labvariation reported in table 7 arecalculated on the results from thenumber of labs indicated in the tableand adjusted to account for the currentpopulation of 16 labs that havedemonstrated the ability to conduct the.Agency's toxicity test. These intervalsindicate that within-lab variation wouldbe unlikely to change the compliancestatus of the tested samples. In otherwords, when the LC50 was above 3percent the Agency is 95 percentconfident that within-lab variationwould not cause a new measurement onthat sample of drilling fluid to be below3 percent. When the LC50 was below 3percent, the Agency is 95 percentconfident that within-lab variation willnot cause a new measurement to beabove 3 percent. If lower LC50s arelinked to lower standard deviations,then the confidence intervals for LC50swill become smaller as the substancebecomes more toxic.

Coefficients of variation (CV) indicatehow much, on a percentage basis, the

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LC5O could vary witldn a singlestandard deviation. However, forregulatory purposes, the Agency isprimarily concerned with the magnitudeof change in toxicity and industry'sability to use either product substitutionwith drilling fluids or treatment/disposalso that, based on within-lab variation,industry would be able to comply withproposed limitations.

Preliminary analysis of the multi-labresults for toxicity tests from the recentstudy continue to support the conclusionthat the test protocol is adequate for usein a regulatory framework. Industry willbe able to use either productsubstitution in order to discharge drillingfluids that comply with a 30,000 ppmlimitation on toxicity or availabletechnology to avoid discharging drillingfluids or drill cuttings:

2. Performance of Granular Media andMembrane Filtration Technologies onProduced Water

Filtration. as an add-on technology toBPT, is being considered as an optionfor treatment of the produced waterwaste stream for both BAT and NSPSeffluent limitations guidelines. To assessthe levels of pollutants in effluents fromtreatment and the efficiency of reducingpollutants in produced water, a "threefacility study" of granular mediafiltration was conducted by the Agencyin the summer of 1989. In addition, datawere received on the performance ofmembrane filtration from an equipmentvendor. The performance of membranefiltration differs from granular mediafiltration in that membrane filtrationremoves much of the soluble oil andgrease from the produced water as wellas suspended solids and the insolubleoil and grease fraction. A summary ofthe results of the use of both types offiltration technologies on producedwater is discussed below.

The Agency selected facilities for the"three facility study" based on: (1) Theiruse of granular filtration, and (2) the oiland grease level being somewhatcomparable to the BPT level prior tofiltration. Not all of these facilities werelocated offshore (one was offshore, onewas onshore, and one was coastal).However, the efficiency of granularmedia filters at each location is notdependent upon the facility's location.Each facility was unique in its handlingof produced waters prior to filtration;however, two of the three use chemicalfeed prior to filtration and all facilitiesreinjected their produced water afterfiltering. Specifically, the onshorefacility uses fresh makeup water,combines it with the produced water,and adds a chemical feed (polymer)prior to the filtration unit. The offshore

facility (a three-well platform located offthe coast of California) combinesproduced waters from the three wellsafter oil/water separation beforeentering the multimedia granularfiltration unit. At the coastal facility, an"ultrahigh" rate filtration unit is utilizedand a polymer is added to the producedwater prior to entering the filtration unit.

Influent and effluent produced watersinto each filtration unit were analyzed.At two of the facilities, the filtrationinfluent waters are the effluent watersfrom gas flotation units (BPT technologybasis). One facility does not use gasflotation. Statistical analyses of datafrom the "three facility study" wereconducted. Results of these analysesand the examination of operationalinformation showed that results fromonly the two facilities which usedpolymers provided satisfactory filterperformance data. A summary of theseresults, shown in Table 8, demonstratesa 40 to 60 percent removal of oil andgrease, from levels approximately at theBPT long-term average level of 25 mg/l,to 11.3 mg/l for the two facilities usingpolymer addition.

TABLE 8.-THREE FACILITY STUDY

STATISTICAL RESULTS

Long Term AverageParameter IConcentrations (ag/)

Influent Effluent

03 and Grease ....................... 27.26 11.33Total Suspended Solids. 44.83 21.17

NOTE: Only the onshore and coastal facilities dataare included.

A vendor of membrane filtrationequipment has supplied the Agency withlimited data from a membraneseparation unit that is operating in theGulf of Mexico and several pilot scaleevaluations at facilities in offshore,coastal, and onshore locations. Resultsfrom the full-scale operation indicatethat, in most cases, regardless of thevalues of TSS and oil and grease in theinfluent, effluent values of less then 5mg/l of oil and grease are readilyattained. In addition, this technologyshows potential for more efficientremovals of soluble oil and grease(organics) than the BPT technology andgranular media filtration technology.Further discussion of this technclogyand its performance is included insection X of today's notice.

C. Analytical Methods

1. Static Sheen TestSince the 1985 proposal of a new

analytical procedure to measure free oilknown as the "Static Sheen Test," othervariations to this method have been

suggested. EPA has reviewed three othermethods: one developed by its Region IXoffice, one by its Region X office, and anadditional version known as the"minimal volume" method. Acomparison of the differences betweenthe 1985 proposal and Region IX'ssuggested method is presented below:

* Receiving water-The "original"procedures require ambient seawater tobe utilized as the receiving water in thetest whereas Region IX procedures callfor tap/drinking water.

* Mixing/stirring-The "original"procedures call for thorough mixing ofboth the test material samples and themixture of test material and receivingwater. Region IX procedures delete allreferences to mixing test materialsamples and require efforts to "minimizeany mixing of the test material in thetest water." This is because of tebtinterferences due to bubbling/foamingand particulate surface deposits causedby mixing or stirring.

* Sample volumes/weights--The"original" procedures specify drillingfluid, deck drainage, or well treatmentfluid samples of 0.15 mL and 15 mL anddrill cuttings or produced sand samplesof 1.5 g and 15 g on a wet weight basis.Region IX procedures call for 15 mLsamples for drilling fluid, deck drainage,or well treatment fluid samples and 15gram (wet weight) samples of drillcuttings or produced sand. Region LX'srequirements simplify the test byrequiring only the largest sample of thewaste stream.

e Observations--The "original"procedures require observations to "bemade no later than one hour after thetest material is transferred to the testcontainer." Region IX requirementsdictate that observations occur"immediately, and at 15, 30, and 60minutes after the test material istransferred to the test container."

* Sheen designation-"Detection of asilvery or metallic sheen, gloss, orincreased reflectivity; visual color, oriridescence on the water surface" isconsidered to be an indication of "freeoil" under the "original" guidelines.Under Region IX guidelines, thediscoloration must cover "more thanone-half of the surface of the test water"and "the appearance of a sheen mustpersist for at least 30 seconds" to beclassified as indicating the presence of"free oil."

The method suggested by Region X isthe same as the 1985 proposal exceptthat the free oil detection criterion issimilar to that for Region IX's version(that a sheen must cover more than onehalf of the surface of the test water).

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The minimal volume test Is aprocedure designed to be moreappropriate for laboratory analysisbecause of the smaller volumes: A 5 mlsample of drilling fluid is used instead of15 ml. Drinking water is used as thereceiving water and mixing isminimized. Observations are madeimmediately and 5 minutes aftercombining the test sample and receivingwater. The free oil detection criterion issimilar to the 1985 proposal.

A study was performed by industrywhich compared the static sheenmethods. This study, among otheraspects of the test, investigated thetendency of false positive readings foreach method. False positive results arethose that show a free oil detection fornon-oil containing samples. Apercentage of false positives resultsgives an indication of the reliability ofthe test. The 1985 proposed method,which was also the same method usedby Region IX at the time of the study,showed 16.76 percent false positives (63samples out of 376). The region Xmethod showed 2.5 percent and theminimal volume method, 21.86 percent.

EPA is considering these variations onthe static sheen test, although themethod proposed in 1985 remainspreferred. The Agency is solicitingcomments, on this and the other threeprocedures as to the appropriateness ofeach method.

2. Diesel Oil Detection and Total OilContent-Proposed Method 1651

The 1985 proposal included proposedmethods for detecting the presence ofdiesel oil in drilling fluids and drillcuttings waste streams. The methodbased on retort distillation and gaschromatography, was subsequentlymodified based on experience gainedduring the conduct of the Diesel PillMonitoring Program (DPMP). The DPMPstudy was performed in order toevaluate the efficiency of dieselrecovery practices after spotting of adiesel pill. This study, performed in1986-1987, is described in the 1988Notice of Availability along with themodified analytical procedure (whichwas corrected in the January 1989 noticeat 54 FR 634).

This modified procedure was themethod accepted by EPA. No commentswere received on it after the 1988 and1989 notices. The method has anestimated detection limit of 100 mg/kg(0.02 percent of diesel oil).Documentation on precision andaccuracy measurements of the testmethod is included in the record for the1988 notice of availability.

The Offshore Operators Committee(OOC) of the American Petroleum

Institute (API) conducted the Diesel PillMonitoring Program (DPMP) in 1986.and1987. One of the objectives of thisprogram was to measure the recovery ofdiesel oil from drilling fluids and drillcuttings wastes. The test method used todetermine the concentration of diesel oilemployed a thermal (retort) extractionto separate the diesel oil from the mudsystem, solvent extraction to separatethe diesel oil from the water andinorganic salts co-extracted in thethermal desorption process, evaporationof the solvent to concentrate the dieseloil in the solvent, and determination ofthe diesel oil in the solvent by gaschromatography. (For an explanation ofgas chromatography, see the preambleto the test procedures for determinationof pollutants in wastewater [49 FR432341.)

This test method was practiced bytwo laboratories, one under contract toEPA and one under contract to industry.One of the conclusions from the DPMPwas that thermal extraction/gaschromatography was capable ofrigorously identifying and quantifyingdiesel oil in drilling wastes when the oilused to spot the pill was used as thereference oil for calibration of the gaschromatography, and when otherpotentially interfering oils were notpresent in the mud at concentrationslarge enough to affect the result. Ininstances where a reference oil were notavailable, number two diesel oil wasused as the reference, and its use madeidentification and quantification of thediesel oil more difficult than when thereference oil was used. In instanceswhere other oils were present in thewastes, determination of the identityand concentration of the diesel oil werealso made more difficult, especiallywhen the concentration of theinterfering oil was large In comparisonto the diesel oil. However, in nearlyevery instance in which a potentialinterference occurred (estimated atapproximately 20 percent of all cases),both the EPA contract laboratory andthe industry contract laboratoryreported that an interference waspresent. Thus, from the testing done inthe DPMP, EPA concluded that thethermal desorption/gas chromatographymethod was capable of determining thepresence and concentration of diesel oilin the waste, and of identifying thosesituations in which an interference waspresent.

As a result, the details of the thermaldesorption/gas chromatography testprocedure and the results obtained wereused to write EPA Method 1651 and todevelop the quality controlspecifications for this method. Themethod included the requirement to use

the diesel oil that was used for the pillfor calibration of the gas chromatograph,if a sample of this oil was available.Method 1651 also provided criteria foridentification of interferences, andsuggested the use of gaschromatography combined with massspectrometry (GCMS) for rigorousidentification of diesel oil if aninterference was suspected.

In 1990, EPA and the oil industryconducted a limited inter-laboratoryvalidation study of Method 1651, usingthe EPA contract laboratory andindustry contract laboratory that hadparticipated in the DPMP, plus threeindustry laboratories that had eitherlimited or no experience with themethod. The results demonstrated thatthe inexperienced laboratories haddifficulty in understanding the method.It was also noted that the EPA contractlaboratory had difficulty with thetherminl desorption apparatus. As aresult, EPA agreed to modify Method1651 to incorporate language clarifyingsome of the operational aspects of themethod. EPA and the industry alsoagreed to investigate alternativeextraction and analysis techniques, inorder to simplify the operationalportions of the method and enable betteridentification of diesel oil in thepresence of interferences. However,because EPA does not want to furtherdelay the regulation of pollutantsdischarged into the environment fromoffshore oil platforms, and because EPAbelieves that Method 1651 is adequatefor determination of diesel oil in drillingfluids and drill cuttings when thismethod is followed, EPA is proposingthis method for determination of dieseloil in drilling fluids and drill cuttings aspublished in the January 9,1989 FederalRegister (54 FR 634).

D. Radioactivity of Produced Water

Within the past year, there has beenmuch concern over the presence andlevels of radium-226 (Ra '29 andradium-228 (Ra 2) in the producedwater waste stream from oil and gasfacilities. Both Ra 2s and Ra 2" arenaturally occurring radioactive isotopeswith half-lives of 1620 years and 5.7years, respectively.

Uranium and thorium (present in deepgeologic formations) undergo a decayseries whereby radium is the firstelement in the decay series that is watersoluble. The level of radium present inthe formation water-which ultimatelybecomes the produced water-has beenfound to be proportional to the salinityof the formation water. There has alsobeen some evidence which indicatesthat the radium-salinity relationship

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may vary depending on the source of theproduced water, e.g., wells producing oilonly or wells producing gas only.

There have been several studiesconducted on produced waters from arange of locations, including offshore,coastal, and onshore facilities. Theresults of these studies have givenpreliminary information on the levels ofradium in produced water across thisrange of locations. These resultsindicate that radium levels in the salineproduced waters from the Gulf Coastregion exceed proposed and existingradium discharge limits for otherindustries. Average open ocean surfacewaters contain 0.05 pCi/1 of Ra226 "whilecoastal waters generally do not containnatural levels of Ra2 6 much higher than1 pCi/1.

In Idte 1986, API initiated anationwide program to gatherinformation on naturally occurringradioactive materials. This programinvolved voluntary sampling andanalysis by oil and gas companiesthroughout the country. Specificsampling and analytical protocols weredistributed to all the interestedcompanies to ensure consistency ofmethodology. Companies wererequested to perform radioactivitymeasurement for service equipment.Companies from twenty of the major oiland gas production states participatedand a large volume of data wereaccumulated. The data weresummarized in a final report from APIentitled, "A National Survey onNaturally Occurring RadioactiveMaterials (NORM) in PetroleumProducing and Gas ProcessingFacilities" dated July 1, 1989. The reportindicates that NORM activity levelsshowed wide variability, bothgeographically and among types of oilfield equipment in the same geographicarea. Although the data were notdeveloped from a statistical plan, sometrends have been noted. The geographicareas with the highest equipmentreadings for radioactivity are the entireGulf Coast crescent (Florida panhandleto Brownsville, Texas), the northeastTexas crescent, southeast Illinois, and afew counties in southern Kansas. Gasprocessing equipment having the highestlevels of radioactivity are reflux pumps,propane pumps and tanks, other pumps,and product lines. Water handlingequipment in the production facilitiescategory exhibits the greatest NORMactivity levels.

Some findings of various other studiesare summarized below:

9 Battelle Laboratories completed astudy for API in August. 1988 on the fateand effects of produced waterdischarges from four facilities in

Louisiana coastal waters (three of whichare covered by the offshoresubcategory). The levels of Ra 221"andRa 28 6 combined were found to rangeanywhere from 605 to 1,215 pCi/1.

9 Kramer and Reid in a 1984publication, "The Occurrence andBehavior of Radium in Saline FormationWater of the U.S. Gulf Coast Region,"reported measured amounts of totalradium ranging from less than 0.2 pCi/1in a produced water sample from a wellin McAllen, Texas to 13,803 pCi/1 in aproduced water sample from VermillionParish, Louisiana.

* In the Leeville oil field in LaFourcheParish, Louisiana, the produced waterswere sampled and analyzed for Ra22 6

levels over a five year period. The levelsof Ra 226varied from 16 pCi/1 to 397 pCi/1.Assuming that the average level in theproduced water was about 280 pCi/1,over the five year sampling period, up to1.76 Curies of Ra u6 were discharged intosurface waters with the produced water.(One picoCurie = I x 10-12 Curies.)

When elevated levels of up to 2,800pCi/1 were discovered in the producedwater discharges in Louisiana, theLouisiana Department of EnvironmentalQuality (DEQ) issued an emergency rulewhich went into effect on February 20,1989. This rule required a radioactivitymeasurement and toxicity tests to beperformed on all existing producedwater discharges that flow into thesurface waters of the state (this includesoffshore structures located in statewaters).

The Louisiana DEQ has completed apreliminary analysis of the datareceived as a part of the sampling underthe emergency rule. There weresubmissions of data from 450 sitesdischarging produced water into thesurface waters of the state. Theanalyses for Ra 226 and Ra 22 wereperformed using the EPA StandardMethod for drinking water. The resultsindicate that Ra 22

6 and Ra 22 8 areprimarily found in the soluble phase andthat one-third to one-half of the siteshad levels of over 300 pCi/1. Themaximum values were 930 pCi/1 of Ra 22

8

and 928 pCi/1 of Ra 228 while the overallaverage values were 158 pCi/1 of Ra 2

2

and 164 pCi/1 of Ra22 .

As a part of the "three facilityfiltration study" conducted by theAgency in the summer of 1989, samplesof the produced water waste streamwere analyzed at different locations inthe treatment system for Ra 22 and Ra22 8

.

Assessment of the raw data showeffluent values after filtration of theproduced water ranging from 10.6 to 213pCi/1 Ra n and 0 to 68 pCi/1 Ra 22, withvery little if any removal by the filters.

Data bases are scattered and, for themost part, preliminary. This informationIs presented today to notice itsavailability and solicit additional data.EPA is concerned about the levels ofradium in produced water and possibleeffects on human health and theenvironment. EPA intends to investigatethe presence of radionuclides inproduced water from facilities furtheroffshore and the effects of radioactivityon the oceanic environment surroundingthe platforms. Following receipt of anydata as a result of today's notice andEPA's investigations, EPA intends toissue a Notice of Data Availability andwill take all available information aboutradioactivity into account in developingfinal regulatory controls on producedwater.

E. Other Studies

EPA and other agencies haveperformed studies regarding severalother aspects of regulatory developingfor the offshore oil and gas rulemakingeffort. The titles and subjects of thesestudies are listed below. Descriptions ofthem and conclusions derived are

_discussed throughout the later sectionsof today's notice where appropriate.

1. "An Evaluation of TechnicalExceptions for Brine Reinjection for theOffshore Oil and Gas Industry." Aninvestigation into the feasibility ofreinjection for produced waters.

2. "The EPA/API Diesel PillMonitoring Program." An evaluation ofthe efficiency of diesel recoverypractices after a diesel pill has beeninjected to free stuck pipe.

3. "Summary of Data Relating toMinor Discharges." An assimilation ofavailable data on mscellaneous andminor offshore oil and gas discharges.

4. "Onshore Disposal of OffshoreDrilling Waste-Capacity and Cost ofOnshore Disposal Facilities." Anassessment of land available andsuitable for disposal of drilling wastesrequired as a result of a zero dischargerequirement. Costs for on land disposalwere also estimated.

5. "An Assessment of Produced WaterImpacts to Low-Energy, Brackish WaterSystems in Southeast Louisiana." Astudy by the Louisiana Department ofEnvironmental Quality on the producedwater impacts on low flow systems.

6. "Produced Water Effects on CoastalEnvironments." Minerals ManagementService.

VIII. Waste Characterization

A. Produced Water and Drilling Wastes

Since the 1985 proposal, no new EPAfield sampling data have been acquired

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Federal Register / Vol. 5K, No. 49 / Wednesday, March 13, 1991 / Proposed Rules

relating to the general character ofuntreated produced waters and drillingwastes. Additional studies have beenconducted on BPT treated producedwaters (the "three-facility study"), onthe appropriateness of the diesel oildischarge prohibition for drilling wastes,and on treatment technologies fordrilling wastes (discussed in the 1988notice). In addition, statisticalevaluations of some previouslysubmitted data were conducted. Theresults of the studies and evaluationsand how they affect this rulemaking arediscussed in later sections of today'snotice.

As discussed in the 1985 proposal, theAgency also categorized the pollutantspresent in drilling fluids waste streamsfor purposes of determining appropriatelimitations and standards. First, drillingfluids contain organics and metals thatare priority toxic pollutants. These toxicpollutants include the cadmium andmercury and organic constituents of thediesel and mineral oils which may beadded to drilling fluids. Also, the largenumber of specialty additives whichmay be used can contain priority toxicpollutants or nonconventionalpollutants. BAT limitations and NSPSare being proposed to control the toxicand nonconventional pollutants. Asdiscussed in greater detail in section IX,the Agency has considered options thatinclude specific numeric limitations oncadmium and mercury, both in the stockbarite and in the drilling wastes (fluidsand cuttings); a prohibition on thedischarge of diesel oil and free oil; and atoxicity limitation. Second, the oil andgrease and total suspended solidspresent in drilling fluids are listedconventional pollutants subject to BCTlimitations as well as NSPS. Theprohibition on the discharge of free oil isthe current BPT requirement; a staticsheen test is proposed to implement thisrequirement. The Agency's approach todetermining the appropriate guidelinesand standards for drill cuttings is thesame as that used for drilling fluidssince the drilling fluids that adhere tothe drill cuttings are the major concern.

The conventional pollutants oil andgrease and total suspended solids willbe subject to BCT limitations and NSPS.

As further discussed in the 1985proposal, for purposes of determiningappropriate guidelines and standards,the Agency categorized the pollutantspresent in produced water wastestreams as follows. Produced watercontains priority toxic organics andmetals. BAT limitations and NSPS arebeing proposed to control thesepollutants. Other chemicals, such asthose contained in biocides, coagulants,

corrosion inhibitors, cleaners,dispersants, emulsion breakers, paraffincontrol agents, reverse emulsionbreakers, and scale inhibitors whichhave not been identified as containingconventional or toxic pollutants, wouldbe considered nonconventionalpollutants subject to BAT limitationsand NSPS. Any pollutants in theseproducts which have been designated"toxic pollutants" would be subject toBAT and NSPS toxic limitations andstandards. Finally, the oil and greaseand total suspended solids present inproduced water would be consideredconventional pollutants subject to BCTand NSPS limitations, and possibleindicator pollutants for the control of thetoxic and nonconventional pollutantssubject to BAT and NSPS.

B. Deck Drainage

Deck drainage results primarily fromprecipitation runoff, miscellaneousleakage and spills, and washdown ofplatform or drill ship decks, floors, andvessels. Virtually any material used atthe site may find its way into the deckdrainage system. Deck drainage oftencontains petroleum-based oils frommiscellaneous spills and leakage of oilsand other production chemicals used bythe facility. It may also containdetergents from washdown operationsand discarded or spilled drilling fluidcomponents. The primary pollutant ofconcern in deck drainage wastes is oiland grease.

New data since the 1985 proposalwere collected on deck drainage as partof a three-facility sampling programconducted during 1989. The Agency alsorecently reviewed extensive records ofdeck drainage collected in the 1970s bythe API. Also, deck drainage informationfrom platforms in Cook Inlet, Alaska,was reviewed.

The three-facility study sampleduntreated deck drainage at two of thefacilities. The API data review obtainedinfluent to the deck drainage clean-upsystem and the actual discharge(effluent). Table 9 presents oil andgrease loadings from deck drainagesamples obtained from these studies andfrom the data contained in the 1985proposal record. The Cook Inlet studyacquired information about thecompounds identified as hazardouschemicals found in deck drainagedischarges. These include paraffins,sodium hydroxide, ethylene glycol,methanol, and isopropyl alcohol.

TABLE 9-DEK DRAINAGECHARACTERISTICS

Study o1 and grease (mg/)

Influent Effluent

Three-facility study ................ 12- NA2.1,3101.

API data. .... 1-16,908 1-673.1985 data .................... 5-183s"

'Ranges of individual sample values' Not analyzed' Range of mo"hly averages of Discharge Mon-

torIng Reports (DMRs) from the 1985 rulemakingrecord.

Both the Agency's data gatheringefforts and API's survey informationindicate the frequency, volume, and oiland grease content of deck drainage ishighly variable. Oil and grease contentof deck drainage may greatly exceed theBPT level discharge limits of producedwater. The content and concentration ofmaterials In deck drainage is highlydependent upon the operating andmaintenance practices at the site, theflow of the deck wash, time betweendeck washings, and the point of timeduring a washing. For example,pollutant concentrations would behigher during the early stages of a deckwashing episode than at the end of theepisode.

For the reasons described above, theAgency has identified priority pollutantconstituents of oil as pollutants ofconcern in deck drainage.

C. Produced Sand

Produced sand consists of particulatematter from the producing formation andother solids, such as scale, corrosion by-products, and paraffin. This materialaccumulates in production tubing,flowlines, and various oil and gasprocess vessels. This waste streamwould also cover any residential sludgesgenerated by chemical polymers used inthe filtration portion of the producedwater treatment system.

These solids must be removedperiodically to restore oil and gasproduction and processing and/or avoidinterruptions to those same activities.The sand is separated out from theproduced water, washed with eitherwater or solvent, and either dischargedoverboard with the produced waterwaste stream or stored in 55-gallondrums and transported to shore fordisposal.

Produced sand generation isestimated at an average rate of I barrelper 2,000 barrels of oil. Actual volumesof sand production experienced byindividual facilities depends upon thecharacteristics of the producingreservoir, sand control procedures

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utilized, and drawdowns experienced bythe reservoir among other factors.

The primary pollutant of concern inproduced sand wastes is oil and grease.The Agency collected new data onproduced solids from three facilities inCalifornia and New Mexico during 1989.A review of individual sample resultsobtained from these facilities showssand and solids associated with oil andgas production to have oil and greasecontents as high as 132,000 ppm.D. Well Treatment, Completion, andWorkover Fluids

Well treatment fluids are used toimprove the hydrocarbon recovery fromproductive reservoirs. These fluids moveinto the formation and either remain inthe hole, return in diffused form with theproduced water, or return as a discreteslug. Some of the more common welltreatment fluids used includehydrofluoric acid; hydrochloric acid;ethylene diaminetetraacetic acid(EDTA); ammonium chloride; nitrogen;various alcohols and solvents such asmethanol xylene, and toluene; andnumerous additives such as ironsequestering agents, corrosioninhibitors, surfactants, and fluiddiverters. The acidic portion of welltreatment fluids are generally spent onthe formation and accompany theproduced water phase. Other portions ofthe treatment fluids may becomeassociated with the produced oil or gasphases.

Once production resumes, welltreatment fluids are usually routedthrough the process equipment used toseparate and treat the normalproduction stream. However, undercurrent practice these fluids may also becaptured in tanks at the surface andthen disposed of by draining the waterportion into the ocean or by transportingthe fluid to onshore disposal sites. Thevolumes and constituents of welltreatment fluids are well-specific, andthe discharge frequency varies betweenlocations. Well treatment dischargeshave been known to range from 12 bbls/day to 1,800 bbls/day.

EPA, during the three-facility study,sampled well treatment fluids at thecoastal production facility. The well wasacidized to enhance the productivity ofthe formation. The samples obtained ofthe treatment fluids prior to treatmentshowed an oil and grease level of 619mg/l. The pH was 2.48. Otherconstituents present were aluminum,iron, magnesium, molybdenum, sodium,zinc, aniline, toluidine, and 2,4,5-trimethylaniine.

Completion and workover fluids aregenerally low solids fluids used toprovide hydrostatic control and/or

prevent formation damage. Typical wellcompletion and workover fluidconstituents may include hydroxyethylcellulose, xanthan gum, hydroxypropylguar, sodium polyacrylate, filteredseawater, calcium carbonate, calciumchloride, potassium chloride, andvarious corrosion inhibitors andbiocides.

Completion and workover fluidscurrently may be collected and recycled.processed with the production streamand then discharged, or dischargeddirectly into the ocean. The decision onwhether to recycle or dispose of thesefluids depends upon the cost and type offluids utilized and various site specificfactors. These fluids are more likely tobe recycled if they are expensive or notcontaminated with other materials.When these fluids are in use, dischargesof completion and workover fluids havebeen estimated to range from 100 bbls/day to 1,300 bbls/day per facility.

Additional data since the 1985proposal have also been obtained by theCook Inlet study conducted by EPA'sRegion X on well treatment, workover,and completion fluids from structures inAlaska. This study lists the hazardousconstituents associated with thesefluids. These hazardous compoundsinclude disodium salt of EDTA,quaternary polyamine, acetylenic acid,hydrochloric acid, hydrofluoric acid,isopropanol, and ethylene glycol. Thesecompounds often comprise over 60percent of the fluid composition.

A comparison was made between freeoil detections (using the Static SheenTest) and oil and grease levels in thisRegion X study. The data show that allwell treatment, workover, or completionfluids did not exhibit a sheen, but oiland grease levels ranged from 0.1 to1,420 mg/l.

Well treatment, completion, andworkover fluids consist of acids,solvents, additives, polymers, or otherlow solids fluids. They are separate anddistinct from drilling fluids. Oil andother organic constituents, which eitherare used in or surface with the welltreatment, completion, or workoverfluids, are the primary pollutants ofconcern.

E. Sanitary and Domestic Wastes

No additional data have beenobtained on sanitary and domesticwastes since 1985.

F. Other Minor Wastes

In addition to those specific wastesfor which effluent limitations areproposed, offshore exploration andproduction facilities discharge otherwastewaters. Although believed to beminor, these wastes were nonetheless

investigated. No control of these otherwastes is being proposed by this notice,since these types of discharges fromexisting operations currently are beingcontrolled by BPJ limits in NPDESpermits. These sources are categorizedinto 15 "minor wastes" and are listed asfollows:

(1) Desalinization unit discharge-wastewater associated with the processof creating fresh water from seawater.

(2) Blow-out preventer fluid-fluidused to actuate the hydraulic equipmenton the blowout preventer.

(3) Laboratory wastes from drains.(4) Uncontaminated ballast/bilge

water (with oil and grease less than 30mg/l)--seawater added or removed tomaintain proper draft.

(5) Drilling fluid, drill cuttings, andcement at the sea floor that result frommarine riser disconnect and wellabandonment and plugging.

(6) Uncontaminated seawaterincluding fire control and utility liftpumps excess water, excess seawaterfrom pressure maintenance, water usedin training and testing of fire protectionpersonnel, pressure test water, and non-contact cooling water.

(7) Boiler blowdown-discharge fromboilers necessary to minimize solidsbuild-up in the boilers.

(8) Excess cement slurry that resultsfrom equipment washdown after acementing operation.

(9) Diatomaceous earth filter mediathat are used to filter seawater or otherauthorized completion fluids.

(10] Waste from painting operationssuch as sandblast sand, paint chips, andpaint spray.

(11) Uncontaminated fresh water suchas air conditioning condensate andpotable water.

(12) Material that may accidentallydischarge during bulk transfer, such ascement materials, and drilling materialssuch as barite.

(13) Water flooding discharges-discharges associated with thetreatment of seawater prior to itsinjection into a hydrocarbon-bearingformation to improve the flow ofhydrocarbons from production wells.These discharges include strainer andfilter backwash water, and treatedwater in excess of that required forinjection.

(14) Test fluids-the discharge thatwould occur should hydrocarbons belocated during exploratory drilling andtested for formation pressure andcontent.

(15) Source Water--Formation waterused for water flooding (excess may bedischarged).

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Many of these wastes are low involume and/or are infrequentlydischarged. In addition, the constituentsin these wastes are mostly the same asthose found in seawater or are inertmaterial. Wastes containing the sameconstituents as the seawater include:Desalination unit discharge,uncontaminated ballast water,uncontaminated bilge water, anduncontaminated sea water. Minor wastesources that contain mostly inertmaterial include source water and sandfrom enhanced recovery operations,boiler blowdown, and uncontaminatedfresh water. The other minor wastescontain some degree of contaminants,but they are difficult to contain (such aswaste from chipping, sanding, andpainting operations, accidental releasesduring bulk transfer operations, andblow out preventer fluid), or theirdischarges are infrequent and expectedto pose minor environmental impact(such as washdown after cementingoperations; diatomaceous earth filtermedia from washing of filtration unit;and drilling fluids, cuttings, and cementat the sea floor resulting from marineriser disconnect and well abandonmentand plugging).

The laboratory waste containsmaterial used for sample analysis andthe material being analyzed. The volumeof this waste stream is relatively lowand is not expected to pose significantenvironmental problems. However,freon may be present in laboratorywaste. With the high volatility of freon,these wastes are not expected to remainin aqueous state for very long and are,therefore, not expected to be present insignificant quantity. The Agency isdiscouraging the discharge of allchlorofluorocarbons, including foam, tothe air or water media, and isproceeding under separate rulemakingwith the identification and approval ofalternate extraction solvents other thanfreon for the oil and grease analyticalmethod.IX. Parameters Selected for Regulation

A. Free OilA change in the test method of

compliance for free oil was proposed in1985. The proposal involved changingfrom a visual inspection after dischargeto a "static sheen" test performed priorto discharge. The static sheen test wouldapply to certain options prohibiting thedischarge of free oil. Affected wastestreams are deck drainage, drillingfluids, drill cuttings, produced sand, andwell treatment completion and workoverfluids.

Based on comments received that theproposed test gave erroneous results, a

modified test was also evaluated.Differences between the proposed testand the modified static sheen test aredescribed in section VII. Below is adiscussion of the reasons that the staticsheen test was proposed in 1985.

Prior to the 1985 proposal, thecompliance monitoring procedurerequired by BPT regulations was avisual inspection of the receiving waterafter discharge. However, since theintent of the limitation is to prohibitdischarges containing free oil that willcause a sheen, the method ofdetermining compliance should examineoil contamination prior to discharge.Also, concerns have been raised that theintent of the existing definition of "nodischarge of free oil" may be violatedtoo easily for the limitation to beeffective. Violations which may resultfrom intentional or unintentional actionsinclude the use of emulsifiers orsurfactants, discharges that occur underpoor visibility conditions (i.e., at night orduring stormy weather), and dischargesinto heavy seas, which are common onthe outer continental shelf. Additionally,concerns have been expressed over theutility of the visual observation of thereceiving water compliance monitoringprocedure for certain discharges duringice conditions common in Alaskanoperations. These include above-icedischarges where the receiving waterwould be covered with broken or solidice, and below-ice discharges where theeffluent stream would be obscured.

To address these monitoringproblems, the Agency developed thestatic sheen test as an alternativecompliance test. The alternative testcontinues the visual observation forsheen but provides for inspection beforedischarge using laboratory procedures.The test is conducted by adding samplesof the effluent stream into a container inwhich the sample is mechanically mixedwith a specific proportion of eitherseawater or fresh water, allowed tostand for a designated period of time,and then viewed for a sheen undercontrolled conditions.

Since the intent of a "no discharge offree oil" limitation is to prevent theoccurrence of a sheen on the receivingwater, the new test method will preventthe discharge of fluids that will causesuch a sheen.

As proposed in 1985, free oil is beingregulated under BAT and NSPS as an"indicator" pollutant for the control ofpriority pollutants (see section IX.Bbelow). Free oil is being regulated underBCT as well. Although it is not aconventional pollutant, as is oil andgrease, EPA is limiting free oil as asurrogate for oil and grease under BCT

in recognition of its previous use underBPT to limit the creation of a visiblesheen.

B. Diesel Oil

In 1985, EPA proposed a prohibitionon the discharge of diesel oil in severalof its regulatory options for drillingfluids and cuttings. EPA is not changingthat proposal in today's notice. Asproposed in 1985 (and included here forinformational purposes), theprohibitions on free oil and diesel oil areintended to limit the oil content indrilling fluids and cuttings wastestreams and thereby control thedischarge of the priority toxics as wellas conventional and nonconventionalpollutants present in those oils. Theprohibition on the discharge of oil isincluded in this option as an "indicator"of the toxic pollutants. The discharge ofdiesel oil, either as a component in anoil-based drilling fluid or as an additiveto a water-based drilling fluid would beprohibited. An indicator pollutant is onethat, by its regulation, will providecontrol on discharges of one or moretoxic pollutants. Diesel oil would beregulated as a nonconventionalpollutant and an indicator because itcontains toxic organic pollutants such asbenzene, toluene, ethylbenzene,naphthalene, and phenanthrene. TheAgency's primary concern is controllingthe priority pollutants in the oils,although these prohibitions also willserve to control nonconventional andconventional pollutants. The Agencyselected the "indicator" approach as analternative to establishing limitations oneach of the specific toxic andnonconventional pollutants present inthese oil-contaminated waste streams.The sampling and analysis datademonstrate that when the amount of oilis reduced in drilling fluid, theconcentrations of priority pollutants andthe overall toxicity of the fluidsgenerally are reduced. The Agency hasdetermined that the proposed controlson diesel oil will provide BAT-levelcontrol of the priority toxic andnonconventional pollutants present indrilling fluids. This method of toxicregulation is necessary because it is noieconomically or technical feasible toestablish specific BAT limitations uponeach of the toxic pollutants present inthe drilling fluids. The technology basisfor this limitation is productsubstitution.

C. Toxicity

In 1985, EPA proposed a limitation ontoxicity as part of the regulatory optionsfor drilling fluids and drill cuttings. EPAis not changing that proposal in this



rulemaking. The limitation is set at30,000 ppm and is based on the toxicityof the most toxic of eight generic drillingfluids in use at the time of the 1985proposal. The toxicity limit is expressedas the concentration of the suspendedparticulate phase (SPP) of the drillingfluid that is lethal to 50 percent ofMysidopsis bahia exposed to thatconcentration of the SPP, i.e., the LC50of the discharge.

The purpose of the LC50 toxicitylimitation on the discharge of drillingfluids is to control the toxic constituentsin drilling fluid discharges. While thelimitations on free oil and diesel oilcould significantly reduce the toxicpollutants present in drilling fluids, otheradditives, such as mineral oil or some ofthe numerous specialty additives, couldgreatly increase the toxicity of thedrilling fluid, especially water-baseddrilling fluids. The toxicity is, in part,caused by the presence andconcentration of priority pollutants.Thus, as proposed in 1985, the toxicitylimitation will control toxic pollutantsand effluent toxicity.

D. Cadmium and Mercury

The trace metals of concern in drillingfluids include cadmium, mercury,barium, zinc, lead, chromium, copper,and arsenic. One of the sources ofbarium and some of the other tracemetals in drilling fluids is barite. Bariteis mined from either bedded or veindeposits. Research has shown that thebedded deposits of barite arecharacterized by substantially lowerconcentrations of heavy metalcontaminants such as cadmium andmercury (Kramer, J.R. et al, "Occurrenceand Solubility of Trace Metals in Baritefor Ocean Drilling Operations,"Symposium-Research onEnvironmental Fate and Effects ofDrilling Fluids and Cuttings, Sponsoredby API, January 1980).

Barite may be contaminated withseveral metals of concern, includingmercury, cadmium, zinc, lead, arsenic,as well as other substances. The Agencybelieves that by limiting the levels ofcadmium and mercury in either thestock barite or the drilling fluid systemdischarge, concentrations of otherrelated metals would be limited as well.EPA is proposing to regulate these twotoxic metals in order to control themetals content of the barite componentof any drilling fluid discharges.Cadmium and mercury are "toxicpollutants" subject to BAT and NSPSlimitations.

The 1985 proposal included proposedeffluent limitations of I mg/kg each ofcadmium and mercury in the dischargeof the whole drilling fluid on a dry

weight basis. The proposed limitationswould be maximum values. Theseeffluent limitations are also included insome of the regulatory options proposedtoday.

In the 1988 notice, two alternativelimitations for cadmium and mercurywere presented. One established limitsat 2.5 mg/kg cadmium and 1.5 mg/kgmercury in the whole drilling fluid. Thiswas developed in response to commentsregarding the cost and availability ofbarite "clean" enough to meet the I mg/kg cadmium and 1 mg/kg mercurylimitations. The 2.5/1.5 mg/kg cadmium/mercury limitations were suggestedbased on the use of barite containing nomore than 5 mg/kg cadmium and 3 mg/kg mercury which, commentersdeclared, was available in adequatesupply. The 2.5 mg/kg cadmium and 1.5mg/kg mercury limitations were derivedusing an assumption that barite isdiluted by 50 percent or more in thedrilling fluid. In the 1988 notice, theAgency also presented the option oflimiting cadmium and mercury at 5 mg/kg and 3 mg/kg, respectively, in thestock barite instead of setting aneffluent limitation in the drilling fluid.

The limitations for cadmium andmercury of 2.5 and 1.5 mg/kg,respectively, in the drilling fluid are nolonger considered appropriate becauseinsufficient support exists for theassumption that a 50 percent dilutionoccurs once barite is mixed with drillingfluids.

Based on additional information sincethe 1988 notice, today's proposal furtherpresents three alternatives for cadmiumand mercury limitations: (1) Maintainingthe 1985 proposed discharge limitationsof I mg/kg cadmium and I mg/kgmercury each in the drilling fluid, (2)limitations based on barite compositionof 5.0 mg/kg cadmium and 3.0 mg/kgmercury as included in the 1988 notice,and (3) limitations of 3.0 mg/kg ofcadmium and 1.0 mg/kg of mercurybased on stock barite composition. Allof these limitations would be amaximum (no single sample to exceed)value.

Recent information to evaluate EPA'scurrent alternatives for metalslimitations comes from data compiledduring a joint effort by EPA and API.The current version of this database,"API-USEPA Metals Database forMetals Content in Drilling Muds-DrillCuttings/Formations--Barites-Sediments," is from April 1990. Thisdatabase contains data sets, from allstudies currently known to EPA andAPI, on the metals content of drillingfluids and drill cuttings.

Analysis of a select set of datasources from this data base, considered

appropriate for the following statisticalanalyses, was performed to determinecompliance rates with each set oflimitations. All of the data sets showpassing rates to some degree for alllimitation options. The limitations for Img/kg cadmium and 1 mg/kg mercury inthe drilling fluids are the most stringent;however, 100 percent compliance wasachieved by the four samples measuredin EPA's Region IX. This is probably dueto the fact that some of the recentRegion IX individual permits havelimitations of 2 mg/kg cadmium and 1mg/kg mercury in the baritecomposition. Region X, which includesin its general permits limitations of 3/1mg/kg cadmium and mercury,respectively, in barite composition,shows a 67 percent compliance rate for1/1 mg/kg cadmium/mercury limit indrilling fluids. Data from Gulf of Mexicofacilities show a lower percentage ofcompliance; however, there arecurrently no metals limitations in theRegion VI general permit. Region VI ispreparing limitations for proposal inresponse to the decision of the UnitedStates Court of Appeals for the NinthCircuit in NRDC v. EPA, 863 F.2d 1420,1432-33 (9th Cir. 1988). For comparativepurposes, EPA is evaluating in itsregulatory options, discussed later insection XII, the most stringent cadmiumand mercury limitations (1/1 mg/kg inthe fluids) and the least stringent option(the 5/3 mg/kg cadmium and mercurylimitations in the barite composition).

In response to comments regardingconcern over availability of baritesupplies, EPA investigated the adequacyof available foreign and domestic -

supplies of barite that meet theproposed cadmium and mercurylimitations of either 1/1 mg/kg in thefluids or 5/3 mg/kg in barite. Thisinvestigation compared foreign anddomestic barite supplies, withcompositions adequate to meet theproposed limitation, to the projectedindustrial demand. The conclusion wasthat supplies are adequate to meet theneeds of offshore drilling operations ifeither limitation were in place.

In addition to noncompliance beingcaused by the use of barite with highcadmium and mercury content,commenters stated that the presence ofcadmium in the formation itself couldcause noncompliance with limitationsapplied at the drilling waste dischargepoint. In particular, an analysis of API's15 Rig Study (discussed later in sectionXIIIA.2) estimates cadmium formationcontribution to drilling fluids as high as79 percent However, this report isbased on certain assumptions for whichEPA is also requesting comment. If,

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however, the metals limitations couldnot be met for this or any other reason,then barging would be necessary forland disposal.

The proposed BAT and NSPSlimitations on cadmium and mercurywould also serve to control theconcentration of other toxic metals inthe drilling waste discharges. The samemetals data base study referencedabove concluded that concentrations ofother toxic metals are positivelycorrelated with concentrations ofcadmium and mercury. This informationsupports EPA's proposal in 1985 toconsider limiting mercury and cadmiumin order to control other toxic metals.

E. Oil ContentThe 1985 proposal included an option

for regulating oil content for drillcuttings. However, this option wasrejected in 1985 because EPA believedthat establishing an oil contentlimitation on drill cuttings was.redundant since the prohibition on thedischarge of free oil appeared to be amore stringent limitation. Data on theperformance of cuttings washertechnologies showed residual oil contentlevels near 10 percent by weight. Dataon the visual sheen test (used then forthe free oil discharge limitation) showedcompliance with this limitation requiredlevels of oil content to be reduced toless than 1 percent.

The Agency continued to studytechnologies for controlling the oilcontent of drilling wastes. and presentedits findings in the 1988 notice. This studywas expanded to explore theapplicability of an oil content limit todrilling fluids as well as to drill cuttings.A number of conclusions evolved fromthis study which EPA reiterates below.

1. Drilling FluidsAn oil content limit for drilling fluids

based on the technologies studied is notappropriate because the volume of fluidsat the end of the drilling that wouldrequire treatment is much greater thanthe technologies evaluated were capableof handling (with regard to treatmentrate). In addition, space is insufficienton platforms to accommodate thesekinds of drilling volumes of fluids thatmust be stored in preparation forprocessing at rates acceptable by thetechnologies.

2. Drill CuttingsThe 1988 notice discussed

technologies for controlling the oilcontent of drilling wastes with respectto both oil-based and water-basedsystems. Oil content of untreated drillcuttings associated with oil-baseddrilling fluids was estimated at 20

percent oil by weight. Untreated drillcuttings from water-based drilling fluidsto which oil had been added for spottingor lubricity were estimated to contain 1percent oil by weight. Data onperformance of thermal distillationshowed that oil content for drill cuttings(associated with either water- or oil-based fluids) could be reduced to 1percent by weight. For solventextraction, reductions were attained to0.3 percent by weight. Thus, it wasstated that drill cuttings from water-based systems to which oil had beenadded for spotting or lubricity would notrequire treatment to comply with an oilcontent limit of 1 percent by weight.

EPA continues to believe thatreductions even to 1 percent in water-based systems are redundant. The freeoil limitation already results incompliance to this level. In addition, thelimitation on diesel oil and toxicityadequately covers toxic pollutantsassociated with oil content of drillingwastes. Reductions of another 0.7percent exhibited by the solventextraction technology do notcompensate for the disadvantages inusing this system. As discussed in the1988 notice, the potential for losses ofchlorofluorocarbon-type solvents to theatmosphere are a major concern forsolvent extraction.

In addition, EPA is not in the positionto develop limitations based on thethermal distillation technologiesbecause this technology has not beendemonstrated either by full-scale or pilottesting to be capable of operating atoffshore facilities and due to safetyconcerns regarding fire hazards. EPA isnot prohibiting the use of thesetechnologies, as it remains an operator'sdecision to choose a preferredcompliance method. However, federallyapplicable limitations based on thesetechnologies are not appropriate at thistime.

F. Oil and Grease

The most obvious pollutant of concernfor produced waters is oil and grease.This pollutant is already regulated underBPT. EPA is proposing certain optionsthat will either equal or be morestringent than the BPT oil and greaselimits for produced water. Oil andgrease is a conventional pollutantsubject to BCT limitations as well asNSPS. EPA is also limiting oil andgrease under BAT as an indicatorpollutant for certain toxic and metalpriority pollutants as well asnonconventional pollutants.

EPA believes it is appropriate toregulate oil and grease under BAT as anindicator for other organic and metaltoxic pollutant removals because the

technologies used to remove oil andgrease also remove additional pollutantsof concern. As discussed in section X,membrane and granular media filtrationalong with chemical polymer additionform the basis for certain regulatoryoptions. Granular media filtration, whileit primarily removes suspendedinsoluble matter, does'achieve a degreeof organic and metal removal as well.Membrane filtration removesconsiderably more of the solublehydrocarbon constituents.

Analysis of data from the three-facility study on performance ofgranular media filtration showedsignificant reductions for totalsuspended solids and oil and grease.Significant reductions in the metalsaluminum, calcium, iron, magnesium,and manganese were also achieved.Additionally, significant reductionswere achieved in 2-propanone. TheAgency believes other compoundswould show significant reductions if alarger number of samples had beencollected.G. Residual Chlorine and FloatingSolids

NSPS limitations on residual chlorineand floating solids were proposed in1985 for sanitary wastes as being equalto BPT. The presence of residualchlorine gives positive indication thatfecal coliform does not exist. BCT andNSPS were proposed in 1985 fordomestic wastes as prohibiting thedischarge of floating solids. Today'snotice does not change that 1985proposal. No BAT limits were proposedfor these parameters because no toxic ornonconventional pollutants of concernwere identified in sanitary or domesticwastes.

H. FoamThe general permit for the Gulf of

Mexico prohibits the discharge of visiblefoam in other than trace amounts for allwastes. Limitations on foam areintended to control discharges thatinclude detergents. EPA believes this isa particularly appropriate pollutant tolimit for domestic wastes. The sourcesof domestic wastes include laundries,galleys, showers, safety shower andeyewash stations, hand wash stationsand fish cleaning stations. Detergentsare an inherent nature of this waste.Foam is a nonconventional pollutantproposed for NSPS.

X. Control and Treatment Technologies

A. Current Practice

The BPT regulations established forthe offshore subcategory are focusedprimarily on the control of free oil and

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the oil and grease content of wastestreams that are discharged to theocean. The information concerningcurrent practice, and discussed in thisQection, was obtained both for the 1979rulemaking and the 1985 proposal. Theonly change in the data obtained forthese previous efforts and discussed atthis time is an updated statisticalanalysis on sample results for BPTproduced water effluents.

" Drilling Fluids

The current BPT regulation for drillingfluids prohibits the discharge of free oil.In general, water-based drilling fluidsare discharged directly to the ocean,because they do not cause a sheenunless the fluids have beencontaminated with oil. In the case ofwater-based drilling fluids to which oilhas been added for spotting or lubricity,current BPT regulations prohibit theirdischarge if they cause a sheen.Compliance with the prohibition of freeoil is achieved by transportation of thespent fluids to shore for land disposal,or treatment to recover the oil and landdisposal of the residual solids. When oil-based drilling fluids are used offshore,the fluids are not discharged, but arereturned to shore for reconditioning andreuse or disposal.

In addition to the requirement for nodischarge of free oil, current NPDESpermits require compliance with toxicitylimits and prohibit the discharge ofdiesel oil. Failure, or anticipated failure,of the drilling fluid system to meet thetoxicity limit or diesel oil dischargeprohibition also causes the spent fluidsto be returned to shore for disposal.

2. Drill CuttingsThe cuttings are segregated from the

drilling fluid with a shale shaker andassociated separation equipment.Existing practices for drill cuttingsbased on the same BPT requirement asdrilling fluids (i.e., no free oil] andcurrent permits for the handling of drillcuttings include: (1) On-site disposal ofdrill cuttings with an oil content thatdoes not cause a sheen on the receivingwater, (2) washing of drill cuttings thatcontain oil at a level that would cause asheen so that they may be dischargedon-site to the receiving water, and (3)transportation to shore for treatmentand/or land disposal.3. Produced Water

Existing technologies for the on-siteremoval of oil and grease from producedwater discharges include gas flotation,gravity separation, chemical addition toassist oil-water separation, and, lessoften, parallel plate coalescers andloose or fibrous media filtration. On-site

disposal methods from offshoreproduction platforms include free falldischarge to the ocean, discharge belowthe water surface, and, at times,reinjection into a subsurface formation.As an alternative, some production sitestransport produced fluids by pipeline toshore facilities for oil-water separationand disposal.

The removal of priority pollutants inBPT treatment systems is minimal.While the sampling data indicatedquantifiable reductions of naphthalene,lead, and ethylbenzene by the BPTtreatment (i.e., by oil-water separatortechnology), the presence of significantlevels of priority pollutants (e.g.,naphthalene and ethylbenzene) in alleffluent samples demonstrates thelimitations of such treatmenttechnologies.

Reinjection is a disposal technique forinjection of produced water into asubsurface formation. When reinjectionis used for disposal purposes only, it ispossible that the receiving formationmay not be the same formation fromwhich produced fluids were extracted.Secondary recovery or pressuremaintenance (water flooding) is apractice under which produced water(or other fluids) is injected into aproducing formation to enhancerecovery of hydrocarbons. Reinjection ofproduced water into a producingformation may serve both purposes, i.e.,disposal of produced water andenhanced recovery of hydrocarbons.

Treatment of produced water (or otherfluids) prior to injection may benecessary, and such treatment mayinclude oil-water separation and/orfiltration to minimize plugging of thereceiving formation. (Oil-waterseparation also serves for recovery of oilas a commercial product.) Also,biocides, corrosion inhibitors andsequestering agents (or ionic bondingagents) may be added to the water toreduce or prevent scaling and corrosionof the injection equipment. The type andamount of treatment depends primarilyon the properties of the receivingformation and characteristics of thefluids being injected.

The concentration of toxic pollutantsin BPT treated produced waters wasinvestigated during an extensivesampling and analysis effort performedat 30 platforms prior to the 1985proposal. Selected conventional andnonconventional pollutants were alsoanalyzed.

EPA updated the statistical analysisof results from the 30 platform study in1989 in order to correct inadequacies inthe consideration of detection limits,duplicate samples, and sampleexclusion. The results of the analysis do

not affect this or previously proposedregulations. Data simply arerecalculated in an effort to moreaccurately estimate BPT effluentpollutant loadings. The results of theanalysis show flow-weighted oil andgrease effluents averaging 89.8 mg/l. Thepriority organics most often present insignificant amounts were benzene, bis(2-ethylhexyl) phthalate, ethylbenzene,naphthalene, phenol, toluene, and 2,4-dimethylphenol. Priority metals presentwere cadmium, copper, lead, nickel,silver, and zinc.

4. Deck Drainage

The current BPT requirement for deckdrainage prohibits the discharge of freeoil (i.e., sheen). Under current practices,deck drainage is either collected andtreated separately for oil removal bygravity separation or is handled by theproduced water treatment system beforedischarge.

A commonly used treatmenttechnology for removal of free oil fromdeck drainage is oil-water separation.This is typically a gravity separationprocess, whereby the waste stream iscollected and diverted to a tank or othervessel. Adequate volume is provided inthe vessel to provide sufficient detentiontime for the free oil and water toseparate. The oil layer is then removedby decanting or skimming and returnedto the production process, and the waterlayer drawn off for discharge. Themajority of platforms in the Gulf ofMexico and offshore California usegravity separation technology on theplatform for treatment of deck drainage.Some California platforms pipe deckdrainage along with produced water toshore for treatment. Alaska operationstypically treat deck drainage wastes onthe platform.

Deck drainage treatment systems andsystems that handle both producedwater and deck drainage operate muchmore efficiently when goodhousekeeping and maintenancepractices are employed. These includeseparation of crankcase oils from thedeck drainage collection system,minimization of spills, discriminate useof detergents, and preventing drillingfluids from entering the deck drainagecollection system.

5. Produced Sand

Produced sand wastes are eithertransported to shore for treatment and/or disposal or are treated by water and/or solvent washes for oil removal toprevent the discharge of free oil anddischarged to the ocean.

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6. Well Treatment Fluids

The current BPT requirement for welltreatment fluids prohibits the dischargeof free oil (i.e., sheen). Well treatmentfluids are used to enhance productionfrom oil and gas bearing zones. Thesefluids are injected into the producingformation as a slug, and some of thefluids remain in the hole. Under currentpractices, well treatment fluids thatresurface are not treated as discretesources but are considered to be mixedwith the oil, gas, and water producedfrom the formation. Therefore, separateprocessing equipment is not provided forwell treatment fluids. The spent acid, orother treatment fluid, moves through thenormal processing system. Afterseparation, well treatment fluids mayend up with the oil, gas, or water phasedepending upon the type of fluid. Forinstance, solvents such as xylene ortoluene will normally become part of theoil stream while nitrogen used as adisplacement fluid will separate withthe gas, and spent acid will bedischarged with the produced water.Minor volumes of well treatment fluidsmay also be disposed of through thedeck drainage system as a result ofleakage and washdown operations.

Normally all of the well treatmentfluids brought to the location areutilized. However, occasionally aportion of the treatment is not used. Ifthis occurs, the service companysupplying the fluids usually retains it forreuse or disposal.

7. Completion and Workover Fluids

Completion and workover fluids aregenerally low solids fluids used toprovide hydrostatic control and/orprevent formation damage. Usually,these fluids are handled by processingthrough the normal production system,capturing for reuse or disposal, or directdischarge into the ocean. This decisionis dependent upon the type of fluid, itscost, and the facilities available.

8. Sanitary Wastes

Sanitary wastes from offshorefacilities are usually treated at thesource by physical/chemical systems.Facilities that are manned continuouslyby ten or more people are required bycurrent BPT regulations to maintain aresidual chlorine concentration in thesanitary waste discharge at a minimumof 1 mg/i for disinfection purposes andto maintain the residual chlorine asclose to this level as possible. Thischlorine residual is achieved byintroducing chlorine in flow dependentamounts. Chlorine is either suppliedfrom commercial sources or may beelectrocatalytically generated from

seawater. This chlorine requirement isbased upon the use of U.S. Coast Guard-approved marine sanitation devices(described in 40 CFR part 140) and isrequired by the BPT regulations.

9. Domestic WastesCurrent permits require domestic

wastes at all facilities to be free offloating solids. This is accomplished bythe use of shredders or screeningdevices. In addition, a general permitcontrols the discharge of foam.

B. Additional Technologies ConsideredThe Agency has investigated

additional control and treatmenttechnologies in the formulation oftoday's proposed regulations. Some ofthese technologies were considered inthe 1985 proposal and some in the 1988notice. Additional technologies,particularly for produced waters, havebeen evaluated since the 1988 notice.These technologies, as well as thosepreviously considered technologies nolonger deemed appropriate for use inthis regulation, are discussed below.

1. Drilling Fluidsa. Product Substitution. Product

substitution was one of three technologybases considered for drilling fluids anddrill cuttings in 1985. Productsubstitution is a method to achieve thedischarge limitations on free oil, dieseloil, cadmium, mercury, and toxicity.Some typical methods for compliancewith these limitations are: (1] Use ofwater-based drilling fluids; (2) use ofproduct substitutes such as low toxicitymineral oils for spotting and lubricitypurposes; (3) use of low-toxicityspecialty additives, and (4) use of baritewith low toxic metals content. EPA'spreferred option for control of drillingfluids in the 1985 proposal was based onproduct substitution. Commentsexpressed concern over the diesel oildischarge prohibition and the fact that itwould force the use of mineral oil.

Studies performed by EPA andindustry (53 FR 41356; 51 FR 29600; 52 FR3046) support EPA's conclusions that: (1)Mineral oil is in common use byoperators in the Gulf of Mexico andAlaska, as well as internationally; (2)mineral oil is an available alternative tothe use of diesel oil; and (3] successrates (for spotting purposes) comparableto those with diesel oil can be achievedwith mineral oil.

Other comments submitted after the1985 proposal suggested allowing thedischarge of diesel oil when it is used asa spotting fluid. In response to this, EPAalso conducted a study to determine therecovery capability of diesel oil whenusing it as a spotting fluid. This study,

known as the "Diesel Pill MonitoringProgram" (DPMP) and described in the1988 notice, supported EPA'sconclusions that pill recoverytechniques implemented during theprogram do not result in recovery ofsufficient amounts of the dieselpill andreduction of drilling fluids and cuttingstoxicity to acceptable levels fordischarge of bulk systems. Systems forapproximately one-half of all wells inthe DPMP contained residual diesellevels between 1-5 percent by weightafter introduction of a diesel pill andsubsequent pill recovery efforts. Inaddition, systems for approximately 80percent of the DPMP wells failed the30,000 ppm LC50 toxicity level after pillrecovery. Almost half that number (40percent of the total] of the DPMP wellshad water-based systems thatcontainedresidual diesel following pill recoveryand showed LC50 values of less than(more toxic than) 5,000 ppm.

For the reasons discussed above, theAgency believes that its proposedprohibition on the discharge of drillingfluid and drill cuttings which have beencontaminated with diesel oil isappropriate for the BAT and NSPSlevels of control for waterbased drillingfluids. The pollutant "diesel oil" is beingused as an indicator of the listed toxicpollutants present in diesel oil. Thetechnology basis for the prohibition onthe discharge of diesel oil in drillingfluids and drill cuttings is substitution ofmineral oil for diesel oil in the fluidsystem and for lubricity and spottingpurposes, and the barging and landtreatment and/or disposal of drillingfluids and cuttings which fail the sheentest or toxicity limits. Such a prohibitionon the discharge of diesel oilcontaminated drilling fluids and drillcuttings was upheld by the UnitedStates Court of Appeals for the FifthCircuit, American Petroleum Institute v.EPA, 858 F.2d 261, 263-66, clarified andrehearing denied, 864 F.2d 1156 (5th Cir.1988) (Bering and Beaufort Seas generalpermits).

b. Zero Discharge. EPA alsoconsidered zero discharge of drillingfluids and drill cuttings in 1985. Thisoption is based upon the transport ofspent drilling wastes to shore forrecovery, reconditioning for reuse, orland disposal. EPA rejected this optionin 1985 because the costs of barging andland disposal were too high. Theavailability of landfill sites was also aconcern.

Since the 1985 proposal, EPA has re-evaluated this option and determinedthat barging drilling wastes istechnicallyand economically feasible.In addition, in response to both industry

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and Agency concerns, EPA has studiedthe availability of land disposal capacity("Onshore Disposal of Offshore DrillingWaste-Capacity and Cost of OnshoreDisposal Facilities," ERC Environmentaland Energy Services Co. for U.S. EPA,January 1991]. The study concluded thatenough land is projected to be availableto support the disposal requirements forthis option. Yet, while available disposalsites exist, EPA has concerns over theuse of large land areas for the disposalof drilling wastes. In addition, theincreased barging and handlingoperations, both on platforms and atdock facilities, require a significantincrease in fuel use and result in largeamounts of air pollutant emissions.Thus, this option is considered intoday's proposal for all structures, andthen, to accommodate the non-waterquality environmental impact concerns,for shallow water structures only andfor structures located 4 miles or lessfrom shore.

c. Clearinghouse Approach. In the1985 proposal, one of the optionsproposed for limiting the discharge ofmuds was referred to as the"Clearinghouse/Toxicity Approach" (50FR 34592). The clearinghouse concept isbased on the fact that operationallysatisfactory drilling fluids can beformulated with constituents that areless environmentally harmful than manythat are available. The generic drillingfluid concept was developed in 1978when the Agency instituted a jointtesting program for various formulationsfor operations in the Atlantic Oceanlease sale areas. EPA Region II and theOffshore Operators Committee (OOC)conducted the Mid-Atlantic BioassayProgram which identified eight water-based drilling fluid types (generic fluids)that encompassed virtually all types ofdrilling fluids in use at the time. Thegeneric fluids were then bioassayedonce as an alternative to having theparticipating operators performbioassay and chemical tests every timea discharge occurred. The selectedgeneric fluids demonstrated relativelylow toxicity in the referenced bioassayprogram. Operators were then allowedto discharge the generic fluid types,including certain approved specialtyadditives ("additives"), withoutconducting additional testing (50 FR34603). Other EPA Regions used theresults from the generic fluids testing inpermits issued for Outer ContinentalShelf (OCS) lease areas.

In the 1985 proposal, Option 2-Clearinghouse Approach discussed theestablishment of a nationalclearinghouse to be administered byEPA. Under this option, the Agency

would serve as repository for all toxicityand related physical and chemicalcharacteristics of base drilling fluidformulations and additives. Theinformation would be used by the publicand operators for use in selecting fluid/additive formulations that would likelycomply with the established toxicityregulation (50 FR 34608].

EPA Region X later issued severalNPDES general permits (Norton Sound(50 FR 23578, June 4, 1985), Cook Inlet/Gulf of Alaska (51 FR 35460, October 3,1986], Chukchi Sea and Beaufort Sea II(53 FR 37846, September 28, 1988)) thatused the generic fluids concept andauthorized the discharge of certainadditives without bioassay testing in thedischarged fluids upon discharge. In allof these permits, Region X listed genericfluids and additives authorized withoutfurther bioassay requirements in a tablein the permit. However, operatorsrequired specialty additives that werenot authorized in the Region X permit.Lacking any method to preciselydetermine the cumulative toxicity ofgeneric fluids discharge with additivesnot in the permits, Region X applied theconcept of additivity to estimate thecumulative toxicity of fluids andadditives.

In the 1985 proposal, the Agencyrejected the Clearinghouse option basedon the time required to develop such aprogram, and the complexity ofmanaging such a program on a nationallevel (50 FR 34592]. Although the Agencyhas received many comments in favor ofa clearinghouse approach to fluids/additive discharge authorization, severalimportant reasons remain that supportrejection of this regulatory option.

First, the Agency's NPDES permittingprogram (sec. 402 of the Act) is based onpoint of discharge ("end-of-pipe")accountability. While bioassays ofdrilling wastes to be disposed of are anestablished measure of compliance with"end-of-pipe" toxicity limits, aclearinghouse approach would requirethe cumulative toxicity of the fluids andadditives to be projected in advance.These advance estimates would have tobe performed for each discharge ofdrilling fluids by hundreds of offshorewells annually. Whether EPA performsthe estimates or industry submits themfor Agency review, the administration ofsuch a program would be complex andwould place a huge administrativeburden on the Agency. Compoundingthis, EPA would be required to maintaina data base with up-to-date informationon fluids and additives, provideresources to track the data, and respondto challenges to clearinghousedeterminations.

Although it has been demonstratedthat the clearinghouse system can beeffective on a small scale, the Agencyhas reservations regarding a nationwideprogram. The success of the Region Xprogram is due, in large part, to therelatively small number of wells drilledin the past and estimated for the future.(The projected number of new drillingsfor the Region X offshore area is 12 peryear in the unconstrained scenario). Anational clearinghouse programinvolving almost 1,000 new drillings peryear and requiring maintenance andupdating of a database containinginformation on numerous additives andfluids combinations would be muchmore difficult to manage and wouldplace an enormous burden on theAgency.

For these reasons, EPA continues toreject the clearinghouse option as acomponent of nationally applicableregulations; however, this would notnecessarily preclude the use of aclearinghouse approach in permits as ameans of implementing toxicity limits inthese regulations, if appropriate.

d. Other technologies. Thermaldistillation and solvent extraction werediscussed both in the 1985 proposal, the1988 notice and a proposed generaldemonstration permit issued by RegionVI on October 16, 1989 (54 FR 42335.The operation of these technologiesresults in a reduction of oil content indrilling wastes. Thus, the regulatedparameter associated with thesetechnologies would be oil content. EPArejected these technologies as a basisfor regulatory control on the generalpremise that limitations on the otherparameters, diesel oil, free oil, andtoxicity are sufficient to reduce toxicsfrom drilling wastes. In addition,thermal distillation is no longer beingconsidered as an option because it hasnot been adequately demonstrated atthe present time as a viable technologyfor use on an offshore platform. Solventextraction is not considered because theAgency remains concerned (as stated inthe 1988 notice) over the potential lossesof chlorofluorocarbon-type solventsfrom these processes to the atmosphere.

Incineration was discussed in the 1985proposal but rejected due to equipmentsize, energy costs, and possible firehazards associated with this process.Some of these technologies may beapplicable for onshore treatment ofdrilling fluids and cuttings that arebarged and transported to centrallocations for reconditioning, treatment,and/or disposal.

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2. Drill Cuttings

EPA is considering requirements fordrill cuttings based on the sametreatment/disposal methods describedin the previous section on drilling fluids.Those methods involve the use ofcertain types of drilling fluids whichwould be mixed with the drill cuttingsextracted from the drilled hole (borehole). The use of water-based drillingfluids, mineral oil instead of diesel oilfor spotting or lubricity, barite with lowcadmium and mercury content, or on-land disposal are the basis for meetingthe proposed requirements. The sametechnologies considered in the 1985proposal and 198 notice, but rejectedfor drilling fluids, were also rejected forcuttings.

3. Produced Water

EPA evaluated each of the followingtreatment technologies in addition to thecontrol technology. These technologieswere considered for implementation atoffshore facilities and onshore whereproduced water is piped to shore fortreatment.

a. Improved Performance of BPTTechnology. The 1985 proposalevaluated the costs and feasibility ofimproved performance of existing BPTtreatment technologies to determinewhether more stringent effluentlimitations for oil and grease would beappropriate. This approach would bebased on improved operation andmaintenance of existing BPT treatmentequipment (e.g.. gas flotation,coalescers, gravity oil separation), moreoperator attention to treatment systemoperation, and possibly re-sizing ofcertain treatment system componentsfor better treatment efficiency.

When discussed in the 1985 proposal,statistical analysis of effluent data fromfacilities sampled during the Agency's30-platform survey showed that an oiland grease effluent limitation of 59 mg/lmaximum (i.e., no single sample toexceed) could be achieved throughimproved performance of BPTtechnology. Problems with the originalanalysis included lack of documentationfor the platforms selected as examplesof improved performance for BPT andthe treatment of samples split for qualitycontrol of lab results as if they wereindependent samples from thewastewater treatment process.

This re-analysis shows that theappropriate limitations are 38 mg/l as adaily maximum value not to beexceeded in any single daily compositeanalysis and 27 mg/I as a monthlyaverage value not to be exceeded. Adaily composite sample consists of fourgrab samples taken at different times

throughout the day. These potentiallimitations can be compared to currentBPT limitations of 72 mg/l dailymaximum and 48 mg/l monthly average.The potential limitations are calculatedbased on the same number of grabsamples per day as current limitations.The data used to determine the potentiallimitations were obtained at platformswhose selection is documented andwhere split sample results are averagedprior to capability analysis for theeffluent.

The 1985 proposal, in its optionsselection process, chose this option forall deep water facilities, and for all gasfacilities regardless of water depth. Thisoption, although still being considered,is no longer a preferred option for thisrulemaking because of the problemsidentified with the performanceevaluation.

b. Filtration. In the 1985 proposal, EPAdiscussed filtration as both an add-ontechnology to BPT and as pretreatmentfor reinjection. The primary purpose offiltration is to remove suspended matter,including insoluble oils, from producedwater. Additional removal of solublepollutants can also be achieved, but it isnot as significant as the reduction ofconventional pollutants such assuspended solids and oil and grease.The 1985 proposal discussed thegranular media technology as an optionfor treatment of produced waters, butonly for BCT and NSPS, since significantreduction in soluble organics or metalswas not evident. For NSPS, the proposalincluded, as an option, limitations forboth TSS and oil and grease of 20 mg/lmonthly average and 30 mg/I dailymaximum. However, this option wasrejected in the 1985 proposal.

After the 1985 proposal, EPAcontinued to evaluate filtrationtechnologies. A granular media filtrationstudy (known as the "three-facilitystudy" and discussed in section VII,Data Gathering) was conducted toacquire additional data on theperformance of this technology. Inaddition, the Agency has been suppliedwith information on a membranefiltration technology and its applicationto treating oil and gas wastes,specifically by the use of ceramicmembranes to treat produced water.Membrane filtration is more effective inremoving constituents of wastewatersthat are normally referred to as solubleand are more resistant to physicalseparation by filters. However, the threefacility study showed significantremovals of hydrocarbons from granularmedia filtration as well. Today's noticepresents additional filtrationperformance data, both for granular and

membrane filters, upon which regulatoryoptions are based.

Granular media filtration involves thepassage of water through a bed of filtermedia with resulting deposition ofsolids. The filter media can be single,dual, or multi-media beds. When theability of the bed to remove suspendedsolids becomes impaired, cleaningthrough backwashing is necessary torestore operating head and effluentquality. In many cases, filters areoperated in conjunction with chemicalpolymers which are added to increaseremoval efficiencies. There are anumber of variations in filter design.These include (1) the direction of flow:down-flow, up-flow, or bi-flow; (2) typesof filter beds: single, dual, or multi-media; (3) the driving force: gravity orpressure; and (4) the method of flowratecontrol: constant-rate or variable-declining-rate.

Filtration is widely used for producedwater treatment prior to reinjection. Thefilters are used for the removal ofsuspended solids and are usuallypreceded by chemical pretreatmentand/or oil removal treatment systems.EPA has investigated this technology,not only as a pretreatment to reinjectionbut as an add-on system to BPT prior todischaxge.

During the three-facility filtrationstudy, influent and effluent sampleswere taken from three granular mediafiltration units used as a means ofpretreatment prior to reinjection. One ofthe facilities was an onshore operationin New Mexico, one was an offshoreoperation off of California, and the thirdfacility was a California coastalproduction facility (gravel island) whichtreated and reinjected produced water.

The gravel island facility generatedapproximately 18,000 barrels per day ofproduced water to be treated. However,in order that there be sufficient waterfor reinjection purposes, approximately5,000 barrels per day of fresh waterwere added to the produced waterbefore filtration, requiring the filters tohandle approximately 24,000 barrels perday. Prior to the addition of fresh waterat the filtration step, skim tanks receiveall the produced water from the oil fieldafter the initial removal of oils fromeach group of production facilities. Theskim tanks remove additional oil bygravity before treatment. The freshwater is then combined with theproduced water along with chemicalsconsisting of a corrosion inhibitor, acoagulant, and a flocculent aid prior tothe filters. These combined waters arepumped to three sand filters. Normally,two filters are operating in an upflow

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direction while the third either is onstandby or backwashing.

Operation of the other two facilities issomewhat similar except that the NewMexico facility does not employ gasflotation, and the offshore facility doesnot employ chemical addition prior tofiltration and subsequent reinjection.

EPA statistically analyzed the datafrom this study to determine effluentlevels achievable from granular-mediafiltration technology. Data from two ofthe three facilities were determined toreflect adequate treatment beyond BPT.The third facility had poor performancedue to the absence of chemical additionprior to filtration.

Effluent limits for oil and grease,based on granular media filtration, arecalculated from concentration datacollected during the three facility study.The daily maximum of 29 mg/i is theestimated 99th percentile for dailycomposite samples. Each dailycomposite value is the average ofchemical analytical results from 12 grabsamples taken at two hour intervalsthroughout the day. The monthlyaverage of 16 mg/i is the estimated 95thpercentile for the average of four dailycomposite samples. For comparisonpurposes, effluent limitations on the

same four grab sample per day basis ascurrent BPT limitations are 32 mg/I as adaily maximum and 17 mg/i as amonthly average.

The use of membrane filters to treatproduced water from oil and gasextraction activities is a relatively newapplication for this process. However,membrane technology has been appliedin a number of industries for manyyears. Ceramic (membrane) filters areused to separate oil, bacteria, solids,and emulsified material from water inseveral industrial applications, includingthe dairy, beverage, and pharmaceuticalindustries. In the case of producedwater, the waste stream is firstchemically pretreated to producediscrete solids that flocculate a portionof the emulsified oil and suspendedsolids. The pretreated water is thenpassed through ceramic filters whichconsist of multichannel, cylindricalpassages in a ceramic block and one ortwo layers of alumina ceramic material

As the wastewater passes through thecylindrical passages, a portion of thewastewater moves though the ceramicmaterial to the outside of the filter,leaving a relatively small volume ofconcentrated retenate behind. Theretenate is recycled to the pretreatment

process where a blowdown periodicallyoccurs. The membranes may requireperiodic chemical cleaning to removefoulants, in addition to the operationalback-pulsing which is used tocontinuously clean the passages in theceramic block. The units are tolerant ofhigh temperatures and pressures, and,due to their compact size, are suited foruse on offshore oil and gas platforms.

At the present time, the Agencyknows of one membrane unit operatingin the Gulf of Mexico and threeadditional units under construction or instart-up phase in the Gulf of Mexico,Canada and the North Sea. The Agencyhas been supplied with informationconcerning the ceramic membranefiltration unit operating in the Gulf ofMexico and data from pilot scale testsconducted in Kansas, Alaska,California, Canada, the Gulf of Mexico,and the North Sea. Table 10 shows theresults of some of these tests. The testsshow that the performance of ceramicmembrane technology is capable ofgiving a range of effluent values of oiland grease as low as I to 9 mg/l evenwhen influent levels are much greaterthan the current BPT levels.

TABLE 10.-MEIBRANE SEPARATION PERFORMANCE: RANGE OF CO4CENTRATION RESULTS By GEOGRAPHIC LOCATION

Oil andgre Total susendedLocelon Test scale Character of feed T g/1 e ss fnt e___________ solids (m/I)

Irl. Effi. Infl. EML

North Se ....................... Bench .......................................... Spitted raw produced water-.................................... 50,000 4 N/A N/ALousia (onshore) ........... Po .............................. .. Effluent from seperator/chemlcal addition ....................... 166-582 <8.8 NJA N/AGulf of M o.... ......... Fulcale .. ..................... Chemical addition/water precipitator ..................... 27-108 <5.0 100-290 - <1Gulf of MPco ................... P....................... Chemical addition/water precipitator/paralel plate co- 105-574 2-5 73-350 <1

Membrane filtration may be utilizedas add-on technology or as replacementequipment for present produced watertreatment technologies and showspotential for more efficient removals ofthe organic compounds than the BPTtechnology and granular filtrationtechnology.

The effluent limits based onmembrane filtration were developedfrom data with an assumed detectionlimit (ASTM Gravimetric Method 4281)of 5.0 ing/L Data obtained fromperformance tests of the membranetechnology are reported lower than thislimit (as low as 1 mg/i), but the Agencybelieves that it is not appropriate fortechnology based limitations to be setlower than the detection limit specifiedfor the Agency approved oil and greasemethod. Hence, the Agency willconsider 5.0 mg/I to be the long-term

average oil and grease concentration.The daily maximum limitation of 13mg/i and the monthly average of 7 mg/1are calculated using variability factorsestimated from the three facility study ofgranular filtration. The variability factorfor the daily maximum limitation isbased on the 99th percentile for thedistribution of daily oil and greasemeasurements where four grab samplesare composited each day. Thevariability factor for the monthlyaverage limitation is based on the 95thpercentile for the average of four dailycomposite samples.

c. Reinjection. Reinjection technologyfor produced water typically consists ofinjecting it under pressure intosubsurface strata or formations.Treatment of the waters prior toinjection is usually necessary, and suchtreatment may include removal of oils

and suspended matter by oil separationand filtration technology. The removalof suspended matter for injection isusually performed to prevent pressurebuild-up and plugging of the receivingformation or strata and/or protectinjection pumps from damage. Biocidesand corrosion inhibitors are typicallyadded to the waters to minimizecorrosion and scaling of injectionequipment. Reinjection technologyresults in no discharge to surfacewaters, i.e.. zero discharge.

Reinjection was considered in the1985 proposal, both for all structures andfor shallow water structures only. EPA,in its preferred option, chose reinjectionfor all shallow water structures exceptfor gas wells, which were allowed todischarge according to the improvedBPT performance option. Gas wellscreate considerably less discharge

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volumes, and it was consideredappropriate not to require zerodischarge for these wells. Zerodischarge was considered appropriatefor shallow water wells (and not fordeep water wells) because EPA foundthat shallow water structures can, anddo, pipe produced water to shorebecause onshore treatment andreinjection is less costly than installingand operating individual on-platformsystems.

As part of today's proposal, and inresponse to industry concerns about thefeasibility of reinjection due to theformation characteristics, EPAevaluated the implementation of thistechnology for both existing and newplatforms. The study showed thatreinjection is generally technologicallyfeasible in all offshore areas, i.e.,suitable formations and conditions areavailable for disposal operations.However, specific locations mayexperience problems in being able toinject due to formation characteristics orproximity to seismically active areas.

EPA is evaluating options which arebased on reinjection of produced waterfrom shallow wells only, or from allproducing structures regardless oflocation or water depth.

d Other Technologies. In 1985, EPAalso considered other technologies suchas carbon adsorption and biologicaltreatment for treatment of producedwaters. Carbon adsorption was rejectedfrom further investigation because thelimited use of this technology does notgive sufficient performance data toevaluate competitive adsorptionphenomena. Biological treatment wasrejected because of the severely difficultproblems associated with biologicallytreating briny waters. Chemicalprecipitation was also considered butrejected because of operationalproblems and non-quantifiablereductions of priority pollutant metalslevels.

The use of hydro-cyclones to treatproduced water was also investigated in1985. This process uses the kineticenergy of pumped produced water tospin it causing materials of differentspecific gravity to separate, in this case,oil and water. Theoretically, the higherthe pressure that the units are operated,the higher the induced gravity and thegreater the oil-water separation andcontaminant removal. The units arerelatively simple to operate and aresuited for use on offshore platforms.Little maintenance is required except forunit or liner replacement due to wear.The removed oil can be combined withthe platform oil production. Informationon this technology at the present timedemonstrated only that it was capable

of meeting the BPT limits for oil andgrease.

4. Deck Drainage, Domestic andSanitary Wastes

The treatment technologies evaluatedfor deck drainage are the same as thosefor the produced water waste stream.No additional technologies beyond BPTand current permit requirements wereconsidered for domestic and sanitarywastes. (However, control of foam is anadditional requirement proposed fordomestic wastes.)

5. Produced Sand

In addition to current permitrequirements zero discharge has beenevaluated for produced sand. This isconsidered feasible because, in mostcases due to the small volumes,produced sands can be stored in barrelsand barged onshore for disposal,especially in cases where barging isalready necessary for other transportrequirements.

6. Well Treatment, Completion andWorkover Fluids

EPA is considering treatment optionsfor zero discharge of all well treratment,completion, and workover fluids, zerodischarge of a 100-barrel buffer on bothsides of the fluids slug plus the slugitself or setting the limitation on thesefluids equal to the BPT requirementprohibiting the discharge of free oil. Forthose fluids where a discrete slug doesnot resurface, the 100-barrel bufferoption would not apply. Rather, thefluids would be treated along with theproduced water.

XI. Best Practicable Technology

EPA is not proposing to modifyexisting BPT limits in this rulemaking;however, the Agency is consideringrequiring the use of a static sheen testmethod for demonstrating compliancewith the BPT as well as BAT, BCT, andNSPS "no free oil" requirement. This isdiscussed in section VII of today'snotice.

XII. Selection of Control and TreatmentOptions for BCT

A. Methodology

The BCT level of control is basedupon the requirement that limitations forconventional pollutants be assessed inlight of "cost-reasonableness." Themethodology for determining costreasonableness was proposed by EPAon October 29, 1982 (47 FR 49176) andbecame effective on August 22, 1986 (51FR 24974). These rules set forth aprocedure which includes two tests todetermine the reasonableness of costs

incurred to comply with candidate BCTtechnology options.

BCT limitations for conventionalpollutants more stringent than BPT areappropriate in instances where the costof such limitations meet the followingcriteria:

1. The removal cost is less than thecomparative cost for removal ofconventional pollutants at a typicalpublicly owned treatment works(POTW); the POTW cost Is $0.46 perpound (in 1986 dollars).

2. The ratio of the incremental BPT toBCT cost divided by the BPT cost for theindustry must be less than 1.29: as such,the cost increase must be less than 129percent.

These two criteria represent the two-part BCT cost test. Each of theregulatory options was analyzedaccording to this cost test to determinethe appropriate BCT limitations fordrilling fluids, drill cuttings, andproduced water are appropriate. BODwas not used because it was not aparameter normally measured inwastewaters from this industry since itis associated with the oil content, e.g.,oil and grease measurement. The use ofBOD and oil and grease would result indouble-counting, thus giving erroneousresults. The differences between thevarious BCT options are explainedbelow.

B. Drilling Fluids and Cuttings

1. Options ConsideredThere are four options considered for

drilling fluids and drill cuttings for BCT.One option is based on water depth, oneoption is based on well distance fromshore, and two are applicable to allstructures regardless of location orwater depth. They are summarized inTable 11 as described below.

TABLE 11.-SUMMARY OF BCT DRILLINGFLUIDS AND CUTTINGS OPTIONS

Option Applicability control level

BPT All All structures ....... BPT.1Structures.

Zero Discharge Shallow water Zero discharge.Shallow, BPT structurms.Deep.

Deep water BPT.1structures.

Zero Discharge 4 miles from Zero discharge.Within 4 shore.Miles; BPTBeyond.$.

>4 miles from BPT.1shore.

Zero Discharge All structures . Zero discharge.All Structures.

IBPT requirement of "no free oil" determined bystatic sheen test

Preferred option In today's notice. BPT wouldapply to all wells in Alaskan waters.

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BPTAJI Structures: This option isequal to BPT as promulgated on April13, 1979 (44 FR 22089) except the staticsheen test would be used to determinefree oil. This was the option proposed in1985.

Zero Discharge Shallow; BPTDeep:This option distinguishes betweenoffshore structures located in shallowwater and those located in deep water.For offshore structures located inshallow water, there is a zero dischargerequirement which is based on recycle/reuse of the drilling fluid portion of thedrilling fluid system and/or transport(mostly by barging) to shore fortreatment and for land disposal of thespent mud system and associatedcuttings. For offshore structures locatedin deep water, discharge requirementsare the same as for the "BPT All" optiondescribed above.

Zero Discharge Within 4 Miles; BPTBeyond. Zero discharge is required forwells drilled at a distance of 4 miles orless from shore. All structures drilled ata distance greater than 4 miles would beregulated by the "BPT All" dischargelimitations option.

Zero Discharge All Structures: Zerodischarge would apply to all offshorestructures regardless of location or thedepth of water in which they arelocated.

TSS and oil and grease are the onlyconventional parameters for which theBCT analysis was conducted for drillingwastes. BOD was not used because itwas not a parameter normally measuredin wastewaters from this industry sinceit is associated with the oil content, e.g,oil and grease measurement. The use ofBOD and oil and grease would result indouble-counting, thus giving erroneousresults. The parameter of settleablesolids was not included as a limitationsoption for consideration because bothdrilling fluids and drill cuttings are sohigh in total solids content, bothsettleable and suspended. The onlyoption suitable for the control ofsuspended solids is zero discharge. Inaddition. EPA is not aware of anycontrol technologies other than zerodischarge that are specifically

developed and operated for the removalof total suspended solids from drillingwastes. Rather, there are technologiesthat remove oils from drilling wastes.Therefore, the only BCT options morestringent than BPT that are consideredare those involving zero discharge.

2. Alaskan WatersComments were submitted to EPA

regarding specific situations in Alaskanwaters (state and OCS waters off ofAlaska) which make compliance with azero discharge requirement based onbarging and land disposal difficult.Reasons for this primarily relate to thesevere weather conditions. Because ofsea ice, tugs and barges can only beused for 4 months in the summer duringopen-water/broken ice season. Inaddition, winter snow and fogconditions restrict visibility. White-outconditions occur restricting air andwater travel. For these reasons, the longdistances required to barge to areaswhich may be suitable for land disposal,and the lack of current land disposalsites, EPA Is proposing to excludeAlaskan waters from zero dischargebased on barging (under any options).

However, zero discharge of drillingwastes may be attained by reinjection ofthe fluids and ground cuttings. EPA Isaware that this is occurring at onelocation in Alaska on an experimentalbasis only. EPA solicits comments onthe feasibility of requiring zerodischarge based on reinjection, ratherthan barging of wastes to land foronshore disposal, for Alaska.

3. Options SelectionCost for BPT for drilling fluids was

calculated based on disposal of oil-based drilling fluids which had to bedisposed onshore because they failedthe sheen test. This Is the only costattributed to BPT. Since oil and greaserelated parameters (such as oil content)are normally measured in drillingwastes and not the oil and greasecontent, the pounds of oil contentremoved is used as a surrogate for oiland grease in the calculations. Thefollowing are annual costs and

conventional pollutant removals fordrilling fluids:Cost: $13,895,000 (1986 dollars).TSS Removal: 186,373,000 lb/yr.Oil Removal: 7,862,000 lb/yr.Total Conventional Pollutants

Removal =194,235,000 lb/yr.Thus, the BPT cost of conventionalpollutant removal for drilling fluids is$0.0715 per pound.

The cost of each regulatory option fordrilling fluids was determined bydividing the "Cost of Pollutant Removal"by the amount of TSS and oil removalachieved under the option. For example,the annual cost of removal for zerodischarge for all structures is$235,984,000 (in 1986 dollars). Zerodischarge achieves an incrementalremoval above BPT of 1.443 billionpounds of TSS and 10.0 million poundsof oil. The BCT (option) removal cost is$0.162 per pound. This is less than thecomparable POTW benchmark removalcost ($0.8/lb in 1986 dollars), thus, theoption passes the first test. The secondtest, the Industry Cost Ratio (ICR), iscalculated as follows:

BCT cost-BPT costJCR =

BTP cost-preBPr cost

$/lb BCT-$/Ib BPT

$/lb for BPT-$/Ib preBPT

.162-.0715ICR - = 1.27.0715-O

The ICR is less than 1.29 thus, theoption passes the second portion of thetes'. As such, BCT limitations based onthe zero discharge regulatory option fordrillirg fluids pass both tests. Table 12presents the results of the BCT cost testsfor drilling fluids. All options pass bothtests.

TABLE 12.-BCT COST TEST FOR DRILLNG FLUIDS

Rc- POW TestOption Cost ($/yr) Removal (/yr) moval (must be ICR Test (must

Cost <0.4%aFsst be < 1.291($/Ib) Va(PiSlA

Zero Disdw" Shallow, BPT Deep ........... ....... ............ 68,387,200 421,073,000 0.162 :Pass ............... 1.27 Pass.Zero iscge .M .. ................................... 236,984,000 1,453,000,000 0.162 Pass ........ 1.27 Pass4 Mile Zem Discwgr BPT B .3601,600 225,360,000 0.162 Paw ..... 1.27 Pss.

Coats expressed In 1986 dollars.ICR: Industry Cost Ratio

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For the various drill cuttings options, Cost-$4,852,000. The BPT cost per pound of conventionalthe cost and conventional pollutant TSS Removal-51,221,000 lb/yr. pollutant removal for drill cuttings isremovals for BPT were calculated based Oil Removal-7,122,000 lb/yr. $0.083 per pound.on the disposal of cuttings from oil The BCT cost test procedure was thenbased muds which required disposal T oal onvetiona lutnt applied to the drill cutting wastes, and aonshore because they failed the sheen Removal= 58,343.000 lb/yr. summary of the results is shown intest. The following are the annual costs Table 13. Each of the options evaluatedand pollutant removals: passes both test criteria.

TABLE 13.-BCT COST TEST FOR DRILL CUTTINGS

Re- POTW Test ICR Test (MustOption moval Must beCost (S/r) Removal (lb/yr) Cost <0.46)a(Pass/ ICR be <1.29)($/Ib) Fi)(Pass/Fal)

Zero Discharge Shaow. BPT Deep ................ 20,924,714 222,909,571 0.094 Pass ................. 0.95 Pass.Zero Discharge All ..................................................................................................... 72,205,000 769,195,000 0.094 Pass ................ 0.95 Pass.4 Mile Zero Discharge; BPT Beyond ........................................................................ 11,199,143 119,303,714 0.094 Pass ................ 0.95 Pass

Costs expressed in 1986 dollars.ICR: Industry Cost Ratio

Zero discharge for all structures wasdetermined to be available andtechnologically feasible technology andit passes the BCT cost test. Upondetailed evaluation, however, certainnon-water quality environmentalimpacts incident to ship transportationand barging surfaced as significantconcerns. As a result of these concerns,"Zero Discharge All Structures" is notbeing proposed as the preferred optionfor BCT control of drilling fluids anddrill cuttings; instead, EPA is proposingas preferred the "4 Mile Zero Discharge;BPT Beyond" option.

Section 304(b)(4)(B) of the CleanWater Act requires EPA to take intoaccount a variety of factors, in additionto the foregoing BCT cost test, inestablishing BCT limitations. Theseadditional factors include "non-waterquality environmental impact (includingenergy requirements), and such otherfactors as the Administrator deemsappropriate." EPA conducted aninvestigation into both the impacts ofbarging and the availability of land fordrilling waste disposal (see sectionXVIII). These non-water qualityenvironmental impacts and energyrequirements and their effect on theselection of EPA's preferred options forcontrol of drilling fluids and drillcuttings covering existing sources andnew sources are summarized here;however, they are discussed in greaterdetail in section XIV and section XVIII.

While EPA's study of non-waterquality environmental impactsestimated that sufficient land disposaliacility capacity is, or would be,available to support a zero dischargerequirement applicable to existing

sources and new sources, EPA isconcerned about the use of the largeamount of land that would be requiredfor this purpose. In addition, EPA iscurrently conducting a study under theResource Conservation and RecoveryAct (RCRA) of wastes associated withoil and gas activities to determinewhether additional, more stringentrequirements are necessary for thetreatment and disposal of such wastes.The outcome of this effort might have asignificant effect on the future availablecapacity and/or cost of land disposal fordrilling fluids and drill cuttings.

The evaluation of bargingrequirements also estimated the airemissions from fuel consumption thatwould be necessary for transport of thefluids and cuttings to shore from existingsources and new sources as a result of azero discharge requirement applicable toall sources. These estimates wereunexpectedly high in air emissions andfuel use in comparison with the otheroptions (See section XVIII). Thus, whilezero discharge is technologicallyfeasible and passes the BCT cost test,other options were explored whichallowed discharges for certain portionsof the industry in order to minimizethese impacts.

EPA has selected the "4 Mile ZeroDischarge; BPT Beyond" option as itspreferred option for BCT effluentlimitations for drilling fluids andcuttings. This option proposes zerodischarge based on barging and landdisposal for new wells drilled onexisting structures at a distance from theinner boundary of the territorial seas(shore) of 4 miles or less. New wellsdrilled on existing structures at a

distance greater than 4 miles would beallowed to discharge after meeting BPTrequirements using the static sheen test.However, for BCT in the Alaska region,BCT would be set equal to BPT for newwells because, as previously discussed.the special climate and safetyconditions that exist for parts of the Nyear make barging especially difficultand hazardous, the lack of currentdisposal sites, and the long distance thatbarging would have to occur over.

The "4 Mile Zero Discharge; BPTBeyond" option, when compared to thezero discharge option for all drillingfluids and drill cuttings, substantiallyreduces the amount of material requiringland disposal. Increases in both airemissions and fuel use are alsosubstantially less. See section XIV. EPAbelieves the non-water qualityenvironmental impacts associated withthe "4 Mile Zero Discharge; BPTBeyond" option, in conjunction withthose associated with the BAT/NSPSpreferred option for control of drillingfluids and drill cuttings, are reasonable,

See sections XV, XVI, XVII, and XVIIIof today's notice for detaileddiscussions of non-water qualityenvironmental impacts, costs, andeconomic impacts.

C. Produced Water1. Options Considered

Seven options were considered byEPA for the regulation of producedwater for BCT. Three options are basedon water depth, one option on platformdistance from the shore, and threeoptions apply to all platforms regardlessof location or water depth. Table 14summarizes the options.

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TABLE 14.-SUMMARY OF BCT PRODUCED WATER OPTIONS

Option Applicability Control level

BPT Alf Structures I ............................................................ All structures ......................................................................... BPT.Filter and Discharge Within Four Miles; BPT Beyond ..... 4 Miles from shore ......................................................... Filter and discharge.

2

< 4 miles from shore ......................................................... BPT.Filter and Discharge Shallow, BPT Deep ......................... Shallow water structures ..................................................... Filter and discharge.2

Deep water structures ......................................................... BPT.Filter and Discharge All Structures .................................... All structures ........................................................................ Filter and discharge.2

Zero Discharge Shallow;, BPT Deep .................................. Shallow water structures ..................................................... Zero discharge.Deep water structures ......................................................... BPT.

Zero Discharge Shallow; Fitter Deep ................................ Shallow water structures ..................................................... Zero discharge.Deep water structures ......................................................... Filter and discharge.'

Zero Discharge All Structures .................. All structures ......................................................................... Zero discharge.

Perferred option in today's notice.'Discharge lmits for "Filter and Discharge" options are being considered based on membrane and granular filtration. Within these options, EPA prefers filtration

limits for oil and grease of 13 mg/I daily maximum and 7 mg/I monthly average, based on membrane filtration. The granular filtration discharge limits for oil andgrease that are being considered are 29 mg/I daily maximum and 16 mg/I monthly average.

The manner of control involvesvarious combinations of treatment anddischarge and/or zero discharge. Thetreatment and discharge technologiesconsidered in the options describedbelow involve either BPT, filtration, orreinjection. The limits associated withthese technologies are for oil and grease.

Filter and Discharge Shallow; BPTDeep: This option distringuishesbetween those offshore structures thatare located in shallow water and thoselocated in deep water. The offshorestructures located in shallow waterwould have requirements based on theuse of filtration (granular media ormembrane separation) technology as anadd-on to the existing BPT technology(dissolved gas flotation). The 1985proposal contained a produced waterfiltration option; however, new datahave been collected for both types offiltration--granular and membraneseparation-since then, and theproposed limits would be based on thenew data. Two sets of limits areconsidered in this option; however, EPAis identifying the set based onmembrane filtration as preferred. Foroffshore structures that are located indeep water BCT would be set equal toBPT. Better operation of the BPTtechnology was not selected aspreferred because of the problems withthe original performance analysis asdiscussed previously.

Zero Discharge Shallow; BPT Deep:This option also makes a distinctionbetween those structures located inshallow water and those in deep water.Under this option, the offshorestructures located in shallow waterwould be subject to a zero dischargerequirement based on reinjection of theproduced water. The reinjection systemwould include oil flotation and gasseparation technology (BPT levelcontrol), filtration, and an injection wellsystem. For offshore structures located

in deep water, BCT would be set equalto BPT.

Filter and Discharge All Structures:All structures, regardless of the waterdepth or distance from shore at whichthey are located, would be required tomeet limits based on filtration of theproduced water prior to discharge. Twosets of limits are considered; however,the limits based on membrane filtrationare preferred.

Zero Discharge Shallow; Filter Deep:This option would require offshorestructures located in shallow water tomeet a zero discharge requirement forthe produced water waste stream, whilethose structures located in deep waterwould be required to meet dischargelimits based on membrane filtration.

Zero Discharge All Structures: Thisoption would require all structures tomeet a zero discharge requirementbased on reinjection of the producedwater.

Filter and Discharge Within 4 Miles;BPTBeyond: Structures located at adistance of 4 miles or less from shorewould be required to meet dischargelimits based on membrane filtration.Structures located at distances greaterthan 4 miles from shore would berequired to meet the existing BPTlimitations only. Other distances,specifically 3, 6, and 8 miles from shorewere being considered and are beingevaluated for suitability with respect tominimizing non-water-quality impacts.

BPTAll Structures: EPA has includedas an option setting BCT equal to BPT.By doing so, EPA is not ruling out thepossibility that, based on the fluctuatingeconomic stability of the oil market,nature of control technology, costs andpollutant removals, compliance withstricter standards may be unachievable.

2. Options Selection

All options considered for BCTregulation were evaluated according tothe BCT cost tests. The pollutant

parameters used in this analysis wereTSS and oil and grease. All options(except the "BPT All Structures" option!fail the BCT cost test. The range ofresults for the first (POTW comparison)test is $3.47 to $3.71 per pound ofconventional pollutant removed. Thus,EPA is proposing BCT equal to BPT frrproduced waters. This proposal is thesame as that proposed in 1985.

D. Deck Drainage

BPT limitations for deck drainage arefor no discharge of "free oil." TypicalBPT technology for compliance with thislimitation is a "skim pile" whichfacilitates gravity separation of anyfloating oil prior to discharge of the deckdrainage.

EPA's preliminary cost estimates forBCT for deck drainage concluded thatthe cost to provide treatment capacityfor deck drainage (which includeddissolved air floatation/filtration) wouldbe considerably more expensive thanthe cost for BPT treatment. BPTtreatment consists of a skim pile and theannual cost to operate a skim pile is onthe order of a few pennies per thousandgallons. The cost to operate a filtrationunit is $3.36 per thousand gallons andthis does not include the operating costof the dissolved air flotation portion ofthe treatment unit. As the second costtest for BCT limits the incremental costto 129 percent of the BPT cost, thisoption would doubtlessly fail this test.

If the filtration/reinjection optionwere employed, the costs andconventional pollutant removals wouldonly increase compared to the filtration/discharge option. The conclusionsreached above for filtration/dischargeoption regarding the second cost testwould also hold for the reinjectionoption. As the second test limits theincremental cost to 129 percent of theBPT cost, the option fails this test also.

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Thus, EPA is proposing BCT equal toBPT for deck drainage. This is the sameas that proposed in 1985.

E. Produced Sand

BPT limitations for produced sandhave not previously been promulgated,however, the current permit requirementfor produced sand is no discharge of freeoil. EPA has not performed a BCT costanalysis on this option, because it isassumed no incremental costs will beincurred since the limitation is currentlyin effect. Therefore, BCT for producedsand is being proposed as equal to nodischarge of free oil.

F Well Treatmpnt. Completion andWorkover Fluids

EP k is not changing the 1985 proposalwhich set BCT equal to BPT fortreatment fluids. No additional cost testshave been performed, however, due to alack of sufficient data on TSSconcentration, both in treated anduntreated wastes.

G. Sanitary and Domestic Wastes

Sanitary wastes are human bodywastes from toilets and urinals. BPTrequirements for discharge are for aminimum free chlorine content residualexceeding 1 mg/l and maintained asclose to this concentration as possible.

Domestic wastes result fromlaundries, galleys and sinks. Currentpermits require that the discharge ofdomestic wastes does not result infloating solids. Treatment usingmacerators is usually sufficient toensure that the discharge complies withpermit requirements.

Given the high cost of offshoreoperations, it would probably be lesscostly to transport these wastes to shorethan to install a treatment unit. No costdata are available on transport costs forshipment to shore. As muds/cuttingscan be transported to shore anddisposed of for $36 to $51 a barrel,onshore disposal of sanitary wastesshould be less costly by an amountequal to the fee charged by the onshoredisposal facility. This cost equals $7 to$10 per barrel. Using the low cost of $26

per barrel and average BOD and TSSlevels reported earlier, the cost is $67per pound of conventional pollutants inthe domestic/sanitary waste. Obviously,this greatly exceeds the POTW cost of$0.46 per pound and requiring transfer toshore would not be justified.

Possibly, some on-platform treatmentprocess could achieve a lower cost perpound of conventional pollutant removalthan onshore disposal, but it is highlyunlikely that it could compete with aPOTW (which is designed to achieve thesame result on a massive scale) in termsof operational cost. Thus, EPA is notchanging the 1985 BCT proposal forsanitary and domestic waste.

XIII. Selection of Options for BAT

A. Drilling Fluids and Drill Cuttings

1. Options Considered

Seven options are being consideredfor BAT control of drilling fluids anddrill cuttings. Below is a discussion ofall of the options with particularemphasis on regulation of toxicpollutants. Table 15 summarizes theseoptions.

TABLE 15.-SUMMARY OF BAT/NSPS DRILLING FLUIDS AND CUTTINGS OPTIONS

Option Applicability Control level

5/3 all structures ................................................................. All structures ........................................................................ 0 Toxicity > 30,000 ppm (SPP).e No diesel oil discharge.e No free oil discharge.'* 3 mg/kg mercury, 5 mg/kg cadmium, both in stock

barite.1/1 all structures ............................................................... All structures ........................................................................ 0 Toxicity > 30,000 ppm (SPP).

* No diesel oil discharge.* No free oil discharge.'• 1 mg/kg mercury, 1 mg/kg cadmium, in the whole

drilling fluid.Zero discharge shallow;, 5/3 deep ............... Shallow water structures .......................................... Zero discharge.

Deep water structures ........................................................ Discharge limits for "5/3 All Structures".Zero discharge shallow;, 1/1 deep ............... Shallow water structures ..................... Zero discharge.

Deep water structures ................ Discharge limits for "111 All Structures".Zero discharge all structures .............................................. All structures ...................................................................... Zero discharge.Zero discharge within 4 miles; 5/3 beyond ...................... < 4 miles from shore ........................................................ Zero discharge.

> 4 miles ............................................................................. Discharge limits for "5/3 All Structures".Zero discharge within 4 miles; 1/1 beyond2 ........... ..... .... < 4 miles from shore ........................................................ Zero discharge.

> 4 miles ............................................................................. Discharge limits for "1/1 All Structures".

'Determined by static sheen test.'Preferred option in today's notice.SPP: Suspended Particulate Phase.

5/3 All Structures: This optionincludes four requirements: (1) Toxicitylimitation set at 30,000 ppm in thesuspended particulate phase; (2) aprohibition on the discharge of diesel oilused either for lubricity or spottingpurposes; (3) no discharge of free oilbased on the static sheen test; and (4)limitations for cadmium and mercury setin the stock barite at 5 mg/kg and 3 mg/kg, respectively. These requirements areto be met by all offshore structuresregardless of the depth of the water inwhich they are located.

The discharge prohibitions on dieseloil and free oil will serve as "indicators"of toxic pollutants. The discharge ofdiesel oil, either as a component in anoil-based drilling fluid or as an additiveto a water-based drilling fluid, would beprohibited under this option. Diesel oilwould be regulated at the BAT levelbecause it contains such toxic organicpollutants as benzene, toluene,ethylbenzene, napthalene, andphenanthrene. The method ofcompliance with this prohibition is touse mineral oil instead of diesel oil for

lubricity and spotting purposes or bargeto shore for recovery of the oil,reconditioning of the drilling fluid forreuse and land disposal of the drillcuttings. EPA believes that in mostcases substitution of mineral oil will bethe method of compliance with thediesel oil discharge prohibition. Mineraloil is a less toxic alternative to diesel oiland is available to serve the sameoperational requirements. Low toxicitymineral oils are also available assubstitutes for diesel oil and continue tobe developed for use in drilling fluids.

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Free oil is proposed to be used as an"indicator" pollutant for control ofpriority pollutants also, includingbenzene, toluene, ethylbenzene, andnaphthalene.

The toxicity limitation is the same asthat proposed in 1985. The purpose ofthe toxicity limitation for any drillingfluids which are to be discharged is toencourage the use of generic or water-based drilling fluids and the use of low-toxicity drilling fluid additives. Thebasis for the toxicity (LC50) limitation,as discussed in the 1985 proposal, is thetoxicity of the most toxic of the genericfluids.

The Agency has considered the costsof product substitution and finds them tobe acceptable for this industry, resultingin no barrier to future entry. (51 FR29600-09 and 53 FR 37849-50, DraftBeaufort Sea and Beaufort/ChukchiSeas General Permits.) Where thetoxicity of the spent drilling fluids andcuttings exceeds the LC50 toxicitylimitation, the method of compliancewith this option would be to transportthe spent fluid system to shore for eitherreconditioning for reuse or landdisposal.

The toxicity limitation would apply toany periodic blow-down of drilling fluidas well as to bulk discharges of drillingfluids and cuttings systems. The term"drilling fluid systems" refers to themajor types of materials (muds) usedduring the drilling of a single well. As anexample, the drilling of a particular wellmay use a spud mud for the first 200feet, a seawater gel mud to a depth of1,000 feet, a lightly treatedlignosulfonate mud to 5,000 feet, andfinally a freshwater lignosulfonate mudsystem to a bottom hole depth of 15,000feet. Typically, bulk discharges of spentdrilling fluids occur when such systemsare changed during the drilling of a wellor at the completion of a well.

For the purpose of self monitoring andreporting requirements in NPDESpermits, it is intended that only samplesof the spent drilling fluid systemdischarges be analyzed in accordancewith the proposed bioassay method.These bulk discharges are the highestvolume mud discharges and will containall the specialty additives included ineach mud system. Thus, spent drillingfluid system discharges are the mostappropriate discharges for whichcompliance with the toxicity limitationshould be demonstrated. In the aboveexample, four such determinationswould be necessary.

For determining the toxicity of thebulk discharge of mud used at maximumwell depth, samples may be obtained atany time after 80 percent of actual wellfootage (not total vertical depth) has

been drilled and up to and including thetime of discharge. This would allow timefor a sample to be collected andanalyzed by bioassay and for theoperator to evaluate the bioassay resultsso that the operator will have adequatetime to plan for the final disposition ofthe spent drilling fluid system, e.g., if thebioassay test is failed, the operatorcould then anticipate and plan fortransport of the spent drilling fluidsystem to shore in order to comply withthe effluent limitation. However, theoperator is not precluded fromdischarging a spent mud system prior toreceiving analytical results.Nonetheless, the operator would besubject to compliance with the effluentlimitations regardless of when selfmonitoring analyses are performed. Theprohibition on discharges of free oil anddiesel oil would apply to all dischargesof drilling fluid at any time.

Cadmium and mercury would beregulated at a level of 5 and 3 mg/kg,respectively, in the stock barite. This isnot an effluent limit to be measured atthe point of discharge but a standardpertaining to the barite used in thedrilling fluid compositions. These twotoxic metals would be regulated tocontrol the metals content of the baritecomponent of any drilling fluiddischarges. Compliance with thisrequirement would involve use of baritefrom sources that either do not containthese metals or contain the metals atlevels below the limitation.

1/1 All Structures: This option alsoincludes four requirements: (1) The sametoxicity limitation as above; (2) the samedischarge prohibition on diesel oil asabove; (3) the same prohibition on thedischarge of free oil as above; and (4)limitations for cadmium and mercury inthe drilling fluids and cuttings at 1 mg/kg each at the point of discharge. Thecadmium and mercury limits are basedupon the use of "clean" stock baritewhich has been costed for use by theindustry. Previous comments havestated that the availability of baritestocks containing low levels of tracemetals could be limited at any giventime due to market conditions. However,EPA investigated the availability of"clean barite" needed to meet the 1/1mg/kg limitations for cadmium andmercury and estimates that sufficientsources of such barite do exist and canbe directed to offshore drilling use inthose cases where an operator would beable to discharge drilling fluids based onmeeting the other requirements of thisoption. The requirements in this optionare to be met by all existing offshorestructures drilling new wells regardlessof the depth of the water in which theyare located or distance from shore.

Zero Discharge Shallow; 5/3 Deep:This option distinguishes betweenoffshore structures located in shallowwater and those located in deep water.For offshore structures located inshallow water, there is a zero dischargerequirement which is the same as thatportion of the "Zero Discharge Shallow;BPT Deep" option for BCT described insection XII, and is based on recycle/reuse of the drilling fluid portion of thedrilling fluid system and/or transport(mostly by barging) of drill cuttings(with residual drilling fluid) to shore fortreatment and/or land disposal. Foroffshore structures located in deepwater, the requirements are the same asthe first option.

Zero Discharge Shallow; 1/1 Deep:This option also makes a distinctionbetween offshore structures located inshallow water and those in deep water.It is the same as the "Zero DischargeShallow; 5/3 Deep" option except thatthe cadmium and mercury requirementsare 1 mg/kg each of these limitationsapply to the drilling fluid and drillcuttings at the point of discharge.

4 Mile Zero Discharge; 5/3 Beyond:Zero discharge is required for wellsdrilled at a distance of 4 miles or lessfrom shore, the same as discussed forthe BCT option identifying 4 miles as adelineation for zero discharge based onminimizing non-water qualityenvironmental impacts. All new wells(on existing structures) drilled at adistance greater than 4 miles would beregulated by the same limitationsincluded in the "5/3 All Structures"option.

4 Mile Zero Discharge; 1/1 Beyond:Same as "4 Mile Zero Discharge"discussed above for wells drilled 4 milesor less from shore and for wells drilledat a distance greater than 4 miles thelimitations are the same as the "1/1 All"option. This option provides for moreadditional control on the toxicpollutants cadmium and mercury in thedrilling fluids and drill cuttings at thepoint of discharge.

Zero Discharge All Structures: Zerodischarge would apply to all offshorestructures regardless of the depth ofwater in which they are located. Thisoption is similar to the "Zero DischargeAll" option considered for BCTlimitations. The only difference is thatthe BCT option is considered for controlof conventional pollutants, while theBAT option focuses on the control oftoxic and nonconventional pollutants.


EPA has selected the "4 Mile ZeroDischarge; 1/1 Beyond" option as itspreferred option for effluent limitations

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for drilling fluids and drill cuttingsbased on the same consideration of non-water quality environmental impactsthat are summarized in section XIIdescribing the BCT options selection.These impacts are discussed further insection XIV and section XVIII of today'snotice. This option proposes zerodischarge based on barging and landdisposal for new wells drilled fromexisting structures at a distance fromshore of 4 miles or less. New wellsdrilled from exiating structures at adistance of greater than 4 miles wouldbe allowed to discharge after meetingrequirements for toxicity, cadmium andmercury at 1/1/ mg/kg respectively, nostatic sheen, and no discharge of dieseloil. However, for the Alaska region, newand existing wells would be covered bythe "I/1 All Structures" option, becausethe special climate and safetyconditions that exist for parts of theyear make barging especially difficultand hazardous, the lack of disposal sitesand the long barging distancesnecessary to get to suitable landdisposal sites.

EPA is proposing, for the wells drilledat a distance greater than 4 miles, the 1mg/kg cadmium and I mg/kg mercurylimitations at the point of dischargeinstead of the 5 mg/kg cadmium and 3mg/kg mercury limitations In the stockbarite because (a) EPA believes it moreappropriate to develop effluentstandards based on point sourcedischarge limitations than on theregulation of only one raw materialcomponent of the discharge (barite inthis case); and (b) it represents controlat the BAT level based on theevaluation of cadmium and mercurydischarge monitoring report (DMR) datareporting concentrations of these metalsin drilling fluids and drill cuttings thatdemonstrate the ability of the industryto meet these limits. These datarepresent compliance informationreported from facilities located offshorein the Pacific Ocean and Gulf of Mexicoand covered by several levels ofconcentration limitations dependingupon the individual (facility or general)permit requirements. Evaluation of theDMR data showed that even thoughindustry was operating under lessstringent metals limits than the 1/1 mag/kg cadmium/mercury limits beingproposed today, discharges would havebeen in compliance with the 1/1 mg/kgrequirement for the four cases where theNPDES permits established a 2/1 mg/kgcadmium/mercury requirement, and 67percent of the time for operators under a3/1 mg/kg cadmium/mercuryrequirement, and even 16 percent of thetime in the Gulf of Mexico, where there

are currently no cadmium/mercuryrequirements.

However, EPA is still considering, forthis option and other options presentedin today's proposal, a 3 mg/kg cadmiumand 1 mg/kg mercury limitation in thebarite based on the continuingevaluation of the availability of bariterequired to meet the limitations. Theinfluence of underground formationcharacteristics on the level of cadmiumand mercury in drill cutting and recycleddrilling fluids will also be considered.

In addition to noncompliance with thecadmium and mercury limitationsattributable to the use of barite withhigh metals content, commentersresponding to the 1985 and 1988proposal notices have stated that thepresence of cadmium in the formationitself could cause noncompliance withlimitations applied at the drilling wastedischarge point. In response to thiscomment, EPA has analyzed data fromthe American Petroleum Institute'sFifteen Rig Study. In this study,operators of 14 rigs volunteered tocollect matched sets of measurements.Each rig collected a sample of drillcuttings, a sample of used drilling fluids,and a 'sample of barite that was presentat the time the first two samples weretaken. Splits or duplicates of thesesamples were analyzed by labsassociated with the Agency. Results ofstatistical analysis indicate that somecadmium present in the drilling fluidscame from a source other than thebarite. In particular, physical analysesby the industry lab indicate that 11 outof 14 rigs had higher cadmiumconcentrations in their drilling fluid thanin their barite. Physical analyses by theAgency lab indicate that 13 out of the 13rigs for which the Agency lab reportedresults, had higher cadmiumconcentrations in their drilling fluid thanin their barite. These results suggest thatcadmium, from a source other thanbarite, is contaminating the drilling fluid.

This conclusion is based on theassumption that metals are uniformlydistributed throughout the barite presentat a single rig and throughout the drillingfluids used on that rig. The Agencyrequests information as to theappropriateness of this assumption andits requests information on whatadditional sources of cadmium mayaffect drilling fluids.

The annualized cost for this optionand its cost-effectiveness are $29.5million and $22 per pound-equivalent,respectively. Two of the other distanceoptions evaluated (6 and 8 miles), aswell as the shallow/deep option, are notas attractive because they do notappreciably reduce the non-water

quality impacts compared to the 4 mileoption. The 3 mile option was not fullyevaluated due to the lack of data onexisting structure locations.

EPA solicits comments on the "4 MileZero Discharge; 1/1 Beyond" option andthe other options as well. EPAespecially invites comment on theappropriateness of the "5/3 AllStructures" and "1/1 All Structures"discharge options and also on the "ZeroDischarge All Structures" option.

See sections XV, XVI, XVII, and XVIIIfor detailed discussions of non-waterquality environmental impacts, costs,economic, and environmental impacts.

B. Produced Water

1. Options Considered

The options considered for producedwater under BAT are the same as thosediscussed previously for BCT. The onlydifference is that while BCT options areintended to control the conventionalpollutants, BAT options focus on thecontrol of toxic and nonconventionalpollutants. Oil and grease remains theonly regulated pollutant. It is beinglimited under BAT as an indicatorpollutant controlling the discharge oftoxic pollutants (see section IX).


EPA has selected for BAT proposaland "Filter within 4 miles; BPT Beyond"option as its preferred option. Thisoption requires all existing productionstructures located at a distance of 4miles or less from shore to meetdischarge limitations based onmembrane filtration, and all existingproduction structures located at a .distance greater than 4 miles from shoreto meet the current BPT limitations. EPAhas determined this option to beeconomically and technically feasible.

Membrane filtration is being used asthe technology basis for the proposedlimits on produced water BAT since it isa demonstrated technology, the EPA hasacquired sufficient data to developeffluent limits of 13 mg/1 for dailymaximum with a composite sample and7 mg/1 for the maximum monthlyaverage. Although not yet in widespreaduse in the oil and gas industry,membrane filtration is a commerciallydemonstrated technology in severalother industries and is considered to beapplicable to oil and gas effluents, asshown by extensive pilot scale tests andmovement toward commercialapplication of this technology to treatproduced water. To obtain additionalfull-scale data other than oil and greaseresults, studies are planned to obtainperformance information from these

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treatment systems with respect tospecific toxic and nonconventionalpollutants. Such data will be used tofurther assess the potential fordeveloping limitations based onmembrane technology and itsavailability will be noticed in theFederal Register if appropriate. EPAsolicits any information available onmembrane filtration technology and itsperformance regarding the treatability ofoil and gas produced waters.

Another set of limitations (29 mg/1 fordaily maximum with a compositesample and 16 mg/1 for maximummonthly average) was considered basedon performance of the granular filtrationtechnology. Granular filtration is beingused in the oil and gas industry.However, EPA chose to proposeproduced water limitations as itspreferred option based on membranefiltration due to its better performanceand projected lower cost relative togranular filtration systems. EPA solicitsinformation concerning the relativetechnical efficiency and cost of thesealternative treatment systems. Shouldmembrane filtration ultimately prove tobe insufficiently demonstrated to serveas the basis for produced watertreatment, EPA will base the limitationson alternative technologies giving strongconsideration to BPT as the basis forBAT since the costs of alternativetechnologies are high.

EPA did not select the most stringentoption, zero discharge based onreinjection, for three reasons. First, thereare questions concerning theapplicability of reinjection to allstructures. Although reinjection may betechnically feasible in general,depending on geological conditions,specific structures would not be able toreinject. Second, the air emissions andfuel use associated with the large pumpsnecessary to reinject fluids areunacceptably high. Finally, reinjectionfor all production structures wouldresult in a 4.9 percent (13 million BOE/year) production loss in barrels of oilequivalent (BOE). This loss ofproduction is not merely a cost concern.Loss of production has independentsignificance in light of the statutorydirective that EPA consider energyimpacts in establishing effluentlimitations and new source performancestandards under the Clean Water Act.

EPA did not select the "Filtration All"option as preferred because of thepotential adverse effects on oil and gasproduction (approximately 3 millionBOE per year based on membranefiltration).

The other options considered wouldrequire filtration for near-shore wellsbut BPT controls for wells farther

offshore; these options use water depthand distance from shore as alternativemeans of reducing the loss of oil and gasproduction. EPA selected the 4 miledistance in order to minimize the loss ofoil and gas production resulting fromcontrols on produced water and becauseit is consistent with the 4 mile distanceused in the preferred options for controlof drilling fluids and drill cuttings. Thisoption also has the lowest associatedfuel requirements and air emissions ofany of the options considered.

Reinjection does eliminate potentialdischarge of radionuclides, particularlyradium-226 and -228. Theseradionuclides have been measured atelevated levels (as high as severalthousand picoCuries per liter) inproduced water discharges on coastaland near-shore areas in the Gulf ofMexico. EPA is concerned about thepossible effects of radium in producedwater discharges on human health andthe environment. Options involving zerodischarge based on reinjection willreceive further consideration as moredata on radionuclides are obtained.

The "Filtration All" option is alsobeing given consideraition as the basisfor BAT for promulgation, since thepotential effect of this option on offshoreproduction is a very small percentage ofthe total of present value of offshoreproduction at existing structures (1.1percent assuming membrane filtration isibtalled}.

EPA solicits comment on the viabilityand appropriateness of the other optionsfor produced water, especially withrespect to the "Filtration All Structures","BPT All Structures" and "ZeroDischarge" options.

See sections XV, XVI, XVII, and XVIIIof today's notice for further discussionof costs, environmental assessment, andeconomic and non-water qualityenvironmental impacts for these options.

C. Deck Drainage

Deck drainage consists of platformand equipment runoff due to stormevents and wastewater as a result ofplatform and equipment washdown/cleaning practices. Options beingconsidered as a basis for BAT for thiswaste stream are either to establish therequirement equal to the current BPTlimits of no discharge of free oil (withcompliance measured by the staticsheen test) or to require the samestandards as those selected for theproduced water waste stream. In manyinstances the deck drainage wastestream has similar pollutantcharacteristics as produced water and iscommingled, and therefore treated, withthe produced water waste stream. Dueto the similarity and commingling of

waste streams, the same BAT options, inaddition to current BPT as an option,presented for the produced water wastestream are considered for the deckdrainage waste stream.

The volumes of deck drainage areminimal compared to the volumes ofproduced water and the deck drainagewaste stream is not a continuous flowwaste stream. Thus, the capacity of theproduced water treatment system wouldnot have to be increased toaccommodate the deck drainagevolumes so it is expected that noadditional costs would be incurred. Asdescribed later in section XV, RevisedTechnologies Costs and Assumptions,and in section XIX, Solicitation ofComments, two sets of costs forproduced water treatment weredeveloped and evaluated for economicachievability. Even the higher costs,which include geographic factors basedon Alaska construction and operationconsiderations and platform structuraladditions at every location for theinstallation of the filtration units, did notsignificantly change the economicachievability. In the case of the modelsused to cost produced water treatmentsystems EPA believes the normal safetymargins included in costing thesesystems will accommodate the minimalcosts that may be associated withintermittent treatment for deck drainage,Thus, the economic impact analysis forproduced water is considered to includethe necessary deck drainage volumes fortreatment to comply with the optionsconsidered. No separate evaluationshave been conducted for the economicanalyses of the options for deckdrainage.

EPA has selected as its preferredoption for effluent limitations for deckdrainage the produced water dischargeoption based on filtration for facilities at4 miles and less from shore and the BPTproduced water oil and greaselimitations for facilities greater than 4miles from shore. This is because deckdrainage is similar in pollutantcharacteristics and can be commingledand treated with produced water.

There are, however, certain situationswhere effluent limitations based onfiltration may not be appropriate fordeck drainage. For example, deckdrainage occurs on drilling platformswhere a production well may not exist;therefore, the produced water treatmentmay not be in place either. Thus, EPA isproposing that the produced water"Filter 4 Mile Within; BPT Deep" optionbe applicable to deck drainage duringthe production phase of the oil and gasextraction operation only, and at earlier

10695



stages, the BPT limits on free oil will-apply.

D. Produced Sand

Produced sand consists of sand andother particulate material from theproducing formation and productionpiping, which comes to the surface alongwith the crude oil and/or gas andproduced water and is separated by theproduced water desander.(settling/screening device] and treatment system.This waste stream could also includesludges generated by any chemicalpolymer use in the filtration portion (orother portions) of the produced watertreatment system. There are two optionsbeing considered for this waste stream:(1) Establish the requirement equal tothe current permit limits of no dischargeof free oil or (2) require zero dischargeby barging and treatment/disposalonshore. The technology basis for theoptions limiting free oil is a water orsolvent wash of produced sands prior todischarge. The method of determiningcompliance with the free oil prohibitionis by the static sheen test discussedearlier.

The prohibition on the discharge offree oil or the zero dischargerequirement for produced sand wouldact to reduce or eliminate the dischargeof any toxic pollutants in the free oil tosurface waters. Becasue this wastestream is of low volume and becausemost facilities currently practice eitherwashing or land disposal to meet thefree oil limitation, the Agency did notattribute any compliance costs to thisproposed option except for nominalcompliance monitoring expenses toperform the static sheen test todetermine the presence of free oil.

The zero discharge option would alsoimpose nominal impacts because thevolume of sand in most locations wouldbe minimal and would be barged toshore infrequently and as part of thebarging of other materials for disposal.

The option selected for proposal iszero discharge for all facilities based onthe minimal volume of waste zerodischarge represents the best technologywhich is both economically andtechnically feasible. However, zerodischarge for structures 4 miles or lessfrom shore and the free oil limitationoptions are still being considered as abasis for the final rule if information ismade available to show that thevolumes of produced sand aresignificantly higher than EPA rawestimates.

E. Well Treatment, Completion andWorkover Fluids

Well treatment, completion andworkover fluids either stay in the hole,

resurface as a concentrated volume(slug), or are dispersed with theproduced water. There are three optionsbeing considered for these wastes: (1)Establish the requirements equal to thecurrent BPT limit of no discharge of freeoil; (2) require zero discharge of anyconcentrated slug of fluids along with a100-barrel buffer on either side of thefluids slug; or (3) meet the samerequirements as produced water (basedon filtration, reinjection, or currentproduced water BPT).

The prohibition on the discharge offree oil and the zero discharge(reinjection along with produced water)requirement are both intended to reduceor eliminate the discharge of toxicpollutants. The method of compliancewith the free oil prohibition would bethe static sheen test.

The zero discharge of the fluids slugwould require capturing 100-barrelbuffers on both sides of the slug, plusthe slug, and barging it to shore for landdisposal. For those fluids that cannot besegregated from the produced waterwaste stream, the produced waterlimitations would apply.For cases where the fluids resurfaceas a discrete slug, EPA has selected zerodischarge of the slug plus a 100-barrelbuffer on either side of it as thepreferred option. Where the fluids arediffused with the produced waters, thepreferred option for produced waterswill apply (e.g., based on filtration at 4miles and less, and produced water BPTlimitations at greater than 4 miles).

F. Domestic and Sanitary WastesThe Agency is not proposing to

establish BAT effluent limitations forthese waste streams, because there havebeen no toxic or nonconventionalpollutants of concern identified insanitary or domestic wastes.

XIV. Selection of Control and TreatmentOptions for NSPS

The basis for new source performancestandards under section 306 of the Act isthe "best available demonstratedtechnology." New facilities have theopportunity to design and implement thebest and most efficient processes andwaste treatment technologies.Therefore, Congress directed EPA toconsider the best demonstrated processchanges, in-plant controls, and end-of-process control and treatmenttechnologies that reduce pollution to the*maximum extent feasible.

The control and treatment optionsinvestigated as a basis for NSPS toreduce the discharge of pollutants inwaste streams generated by the offshoresegment of this industry consist of thoseoptions evaluated for use in the BCT

and BAT levels of control. No additionaldemonstrated technologies wereidentified that would be applicable tonew sources only. However, some of theoptions considered but not identified aspreferred for BAT, or for that matterNSPS, are still being seriouslyconsidered for the basis of NSPS in thefinal rule, provided that additionalinformation can be obtained. Since all ofthe options considered are the same aspreviously described for BCT and BAT,with the exception of the proposedNSPS prohibition on discharge of foamfor domestic wastes, no detaileddiscussion is repeated here.

For drilling fluids and drill cuttings,the preferred option for proposal is thesame as BAT, "Zero Discharge Within 4Miles; 1/1 Beyond", and is based uponthe same factors. These factors are theminimization of potential non-waterquality environmental impacts due tothe large volume of solids requiring landdisposal and the air emissions and fueluse associated with transportation ofthe solids to land. It is estimated thatonly about four percent of the new welldrillings will be on existing structures(platforms); thus, the assignment ofcosts and impacts for evaluating thelimitations are shown under the NSPSselection for drilling wastes. The non-water quality environmental impacts aredescribed in section XVIII, along withthe evaluation conducted to minimizethe estimated impacts.

Section 306(b)(1)(B) of the CleanWater Act requires EPA, in establishingnew source performance standards, totake into account any non-water qualityenvironmental impacts and energyrequirements incident to the rules. Non-water quality environmental impactsand energy requirements have played animportant role in EPA's selection of itspreferred NSPS option for control ofdrilling fluids and drill cuttings.

The most stringent option consideredby the Agency, zero discharge of drillingfluids and drill cuttings for all structures(based on transport of spent drillingwastes to shore for recovery,reconditioning for reuse or landdisposal) was determined to betechnologically and economicallyachievable. However, a zero dischargerequirement applicable to all structureswould cause an enormous amount ofsolids (estimated at 8.2 million barrelsper year) to be barged to shore for landdisposal. In developing this proposal,EPA studied the non-water qualityenvironmental impacts caused by thebarging of this quantity of drilling wasteto land and the availability ofappropriate landfill sites for its ultimate

10696



disposal. (See section XVIII of today'snotice).

EPA's evaluation of the non-waterquality environmental impacts ofbarging focused on the air emissionsthat would result from the transport of8.2 million barrels of drilling fluids anddrill cuttings to shore. Air emissionsfrom sources on the OCS are a matter oflongstanding concern to the Agency,Congress and states adjoining OCSareas where oil and gas operations takeplace. Section 801 of the Clean Air ActAmendments of 1990 (codified as newsection 328 of the Clean Air Act) reflectsthis concern. This new provisionrequires EPA to "establish requirementsto control air pollution" from OCSsources located offshore of the statesalong the Pacific, Arctic and Atlanticcoasts and along the Gulf coast off theState of Florida. The air pollutioncontrol requirements that are to beestablished pursuant to new section 328must "attain and maintain Federal andState ambient air quality standards"and comply with the provisions of title I,part C of the Clean Air Act, which relateto the prevention of significantdeterioration. For sources located within25 miles of the seaward boundary ofthese states, the requirements "shall bethe same as would be applicable if thesource were located in thecorresponding onshore area."

New section 328 identifies "platformand drill ship exploration, construction,development, production processing andtransportation" and "emissions fromany vessel servicing or associated withan OCS source" as specific air pollutantsources of concern.

In addition, new section 328 of theClean Air Act requires the Secretary ofthe Interior, in consultation with theAdministrator of EPA, to "assurecoordination of air pollution controlregulation for Outer Continental Shelfemissions and emissions in adjacentonshore areas" for portions of the Gulfcoast OCS off the states of Texas,Louisiana, Mississippi and Alabama.

The Agency has estimated that the airemissions associated with barging toattain zero discharge of drilling fluidsand drill cuttings would be 6,352 shorttons of particulates, nitrous oxides,carbon dioxide, hydrocarbons andsulphur oxides per year. This estimatewas unexpectedly high in comparison toother options, which ranged from 532short tons for the "5/3 All" and "1/1All" options to 2,116 short tons for the"Zero Discharge Shallow; 5/3 Deep" andthe "Zero Discharge Shallow; 1/1 Deep"options. (See Table 22.)

In examining energy requirments, EPAestimated the amount of diesel fuel thatwould be required to operate the barging

systems associated with the optionsunder consideration. The amount of fuelthat would have to be expended toattain zero discharge was estimated at818M29 barrels per year. This figure alsois significantly higher than the fuel useestimates associated with the otheroptions, which ranged from 79,517barrels per year for the "5/3 All" and"1/1 All" options to 293,535 barrels peryear for the "Zero Discharge Shallow;5/ 3 Deep" and the "Zero DischargeShallow: 1/1 Deep" options. (See Table22.)

Finally, EPA studied the availabilityof land for drilling waste disposal inconnection with its evaluation of thecontrol options for drilling fluids anddrill cuttings. The study estimated theavailable capacity of all existinglandfills in the Gulf of Mexico regionand California. The Agency concludedthat sufficient capacity is, or would be,available to support a zero dischargerequirement. However, the 8.2 millionbarrels of drilling wastes that would begenerated annually as a result of thezero discharge requirement representsapproximately 57 percent of the capacityof the existing landfills in the Gulf areaand California (there are currently nolandfills in Alaska that accept thesewastes), and approximately 18 percentof the projected available landfillcapacity in these areas. EPA isconcerned about the use of this segmentof existing landfill capacity for thedisposal of drilling wastes. Theseconcerns are compounded by the factthat EPA is currently conducting a studyunder RCRA of wastes associated withoil and gas activities to determinewhether additional, more stringentrequirements are necessary for thetreatment and disposal of such wastes.The outcome of this effort might have asignificant effect on the future availablecapacity and/or cost of land disposal fordrilling wastes and drill cuttings.

Thus, while zero discharge istechnologically and economicallyachievable, EPA determined that thenon-water quality environmentalimpacts and energy requirementsassociated with this option aresignificant enough to rule out theselection of this option as preferred.

The volume of drilling wastes thatwould have to be transported to shorefor disposal as a result of the "4 MileZero Discharge; 1/1 Beyond" option is1.6 million barrels annually, a reductionof approximately 80 percent ascompared to zero discharge. Thisreduces the impacts on landfill capacityaccordingly. The fuel requirementsassociated with this option are 173,360barrels per year, also reduction of 80percent. Annual air emissions are

reduced by about 82 percent, from 6,352short tons to 1,166 short tons comparedto the zero discharge option. EPAbelieves these non-water qualityenvironmental impacts associated withthe "4 Mile Zero Discharge; 1/1 Beyond"option are reasonable. The "4 Mile ZeroDischarge; 1/1 Beyond" option also hasthe advantage of eliminating dischargesof drilling fluids and drill cuttings fromthe sensitive marine areas within fourmiles of shore while subjectingdischarges seaward of that area tostringent controls. The other distanceoptions (6 and 8 miles), as well as theshallow/deep options, do notappreciably reduce non-water qualityenvironmental impacts compared to the4 mile option, and insufficientinformation is available to evaluate 3miles.

For NSPS produced water, in additionto the proposed option of "FiltrationWithin 4 Miles; BPT Beyond" which isthe same as the BAT proposal, and the"Filtration All Structures" option whichis also being strongly considered, zerodischarge at 4 miles or less inconjunction with BPT or filtrationbeyond 4 miles are being considered forNSPS. The proposed NSPS option is thesame as BAT based on the estimatedloss of production associated with theother options. For example, the loss forthe "Filtration All" options, althoughsmall in percent of total production (0.2percent], is still quite large in barrels ofoil equivalent (1.1 million BOE per year).These considerations are discussed inmore detail in section XIII.B describingthe BAT options selection for producedwater. For the reinjection options, thegeneration of additional air emissionsdue to the increased use of high pressurepumping is significant, althoughselecting a 4 miles and less from shoreoption requiring zero discharge based onreinjection will minimize the airemissions impact to some extent. Thistechnology option would reduce overalldischarge of pollutants and eliminatewithin 4 miles of shore the discharge ofradionuclides, specifically radium-226and radium-228. Preliminary informationshows that elevated levels of theseradionuclides are present in producedwater, with some of the highestmeasurements coming from oil and gasproduction areas along the Gulf ofMexico coast. EPA may considerreinjection technology options furtherbased on obtaining additional data,further characterizing the radionuclidesin produced water discharges, andidentifying geographic areas where thereare pollutants of concern in producedwater. See sections XV, XVI, XVII,XVIII of today's notice of further

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discussion of costs, environmentalassessment, and economic and non-water quality environmental impacts forthese options.

For well treatment, completion andworkover fluids that resurface as adiscrete slug, NSPS is proposed as zerodischarge of the slug plus a 100-barrelbuffer on either side of the slug. In thecase where these fluids are diffusedwith the produced water, the limits ofthe preferred option for produced water(Filtration Within 4 Miles; BPT Beyond)will apply. NSPS for deck drainageduring production is proposed as equalto the preferred option for producedwater. During drilling operations, NSPSfor deck drainage is proposed to beequal to BPT limits prohibiting dischargeof free oil. Zero discharge is proposed as

NSPS for produced sand. NSPS forsanitary wastes is being proposed equalto current R'PT. NSPS for domesticwastes is proposed as equal to currentpractice prohibiting discharge of floatingsolids, plus the additional requirementfor no visible discharge of foam.

XV. Revised Technology Costs andAssumptions

A. Drilling Fluids and Cuttings

In order to evaluate the cost of controltechnologies for drilling wastes, adatabase was established that defined:

e Projections of the number of wellsthat will be drilled over the next 15-yearperiod in each geographic region.

* Characteristics of a "model well"describing average levels for parameters

such as well depth, volume of wasteassociated with drilling activity, use ofadditives to aid in drilling, and length oftime to drill a well.

* Characteristics of driling wastes,specifying pollutant concentration andphysical properties of the waste specificto certain drilling scenarios.

e Failure rates of drilling wastes withrespect to certain discharge limitationscompliance tests (e.g., static sheen,toxicity).

e Disposal costs for transportationnnd land disposal of drilling wastes.

Table 16 summarizes the currentpermit requirements that were used asbaseline requirements in the cost as wellas economic analyses.

TABLE 16.-SUMMARY OF CURRENT REQUIREMENTS FOR DRILUNG FLUIDS AND CUTTINGS FOR THE OFFSHORE PERMITS

Requirement Gulf of Mexico Pacific Alaska

No discharge of oil-based drilling fluids and cuttings (BPT Yes ...................................................... Yes ...................................................... Yesrequirement).

Metals Limitation ........................................................................ No ....................................................... Yes (barite) ........................................ Yes (barite)- Mercury (mg/kg) .............................................................. ......................................................... I ..........................................................1--Cadmium (mg/kg) ............................................................ ......................................................... 2 .......................................................... 3

No discharge of oil in detectable amounts:- for Lubricity ...................................................................... Yes (Diesel) ....................................... Yes (Diesel) ....................................... Yes (Diesel)

a Pill ............................................................................ No I ..................................................... No I ..................................................... Yes (Mineral) 2Toxicity limitation ........................................................................ Y es ...................................................... Yes ...................................................... YesLimit (drilling fluids) .................................................................... 30,000 ppm SPP ............. 30,000 ppm SPP ..................No discharge of "free oil"; static sheen test (cuttings No ...................................................... Yes ...................................................... Yes

from use of water-based drilling fluids).

SSP* Suspended Particulate PhaseDiesel pill plus a 50 bbl. buffer of drilling fluid on either side of the pill cannot be discharged; mineral oil can be discharged without a buffer.'Mineral oil pill plus a 50 bl. buffer of drilling fluid on either side of the pill cannot be discharged. Diesel not allowed.

* With a pre-approved drilling fluid system.

Using these data, regulatory options,as defined in section XII, wereevaluated to determine costs andpollutant removals associated withcompliance with each of the options. Inevaluating the cost of regulatory options,it was assumed that all drillingoperations would utilize materialsubstitution rather than have to takewaste onshore for disposal. Thisincludes substituting mineral oil fordiesel and using "clean" barite. For thezero discharge options, however, suchmaterial substitution was not utilized.

An analysis of each option wasconducted to determine:

* Number of wells affected* Cost incurred by industry to comply

with the regulations* Volume and percent of drilling

waste requiring onshore disposal• Direct and incidental pollutant

removalCosts are presented on an annual

basis only; no capital costs arepresented, because no capital costswere identified for any of the drillingfluids and drill cuttings options.

Compliance costs for each option arebased on the cost of materialsubstitution (e.g., mineral oil for diesel)or the cost of onshore disposal ofdrilling waste. No distinction was madebetween BAT and NSPS wells becauseit is estimated that all but approximately4 percent of the wells will be considerednew sources. The results of the analysesare presented in Table 17 for drillingfluids and drill cuttings combined.

TABLE 17.-ANNUAL COMPLIANCE COST/POLLUTANT REMOVALS FOR REGULATORY OPTIoNis: DRILLING FLUIDS AND DRILL CUTTINGSCOMBINED-NSPS AND BAT/BCT

1.Zero Zero Zero Zero at 4 Zero st 45/3 All 1/1 All !discharge discharge ischarg6/ Al 1/Al shallow; .5/ shallow, 1/ dishre mile; 5/3 mile; 1/113 deep I deep all beyond* beyond-

Cost of pollution removal ($1000/yr) ...............................................................Volume of drilling fluid barged (1000/bbl/yr) .................................................Priority pollutant rem oval (lb/1) ....................................................................Nonconventionals rem oval (Ib/yr) .............................................................Oil removal (1000/1b/yr) ....................................................................................Incidental pollutant rem oval Ob/yr) ..................................................................

22,029552

29,000790,000

4,248190,000

32,564552

34,840790,000

4,251188,000

108,5482,746

364,494678,060

6,308472,200

116,3822,746

387,000662,570

5,840468,900

308,1898.190

965,000957,000

13,995751,000

63,0841,596

193,000738,000

5,274318,000

72,2521,596

183,500733,000

5,267317,000

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TABLE 17.-ANNUAL COMPLIANCE COST/POLLUTANT REMOVALS FOR REGULATORY OPTIONS: DRILLING FLUIDS AND DRILL CUTTINGSCOMBINED-NSPS AND BAT/BCT--Continued

Notes:1. Approximately 4 percent of the costs and removals are associated with new wells at existing structures covered by OCT/BAT.2. All removals shown Incremental to BPT.* Excludes Alaska region from the zero discharge requirement

In determining pollutant removals,specific pollutants were selected forevaluation based on their consistentlysignificant presence in offshore oil andgas wastes. Removals are considereddirect or incidental. The prioritypollutants, conventionals, oil, andnonconventionals listed in Table 17 arepollutants directly removed by thetechnologies being evaluated. For thepriority pollutants, pollutant removalswere calculated on the sum total ofconcentrations for benzene,naphthalene, fluorene, phenanthrene,phenol, cadmium, mercury, antimony,arsenic, beryllium, chromium, copper,lead, nickel, selenium, silver, thallium,and zinc. The nonconventionalsevaluated consisted of classes oforganics including the alkylatedhomologs for benzene, naphthalene,biphenyl, fluorene, and phenanthrene,the alkylated phenols for ortho-cresol,meta- and para-cresol, C2 phenols, C3phenols, and C4 phenols, and totaldibenzothiophenes. An additionalcategory labeled "incidental removal"was included to measure removals ofpollutants be technologies notnecessarily intending to remove them.These pollutants are the same as thepriority pollutant metals and includecadmium, mercury, antimony, arsenic,beryllium, chromium, lead, nickel,selenium, silver, zinc, and thallium.

B. Produced Water

In order to evaluate regulatory optionsfor discharge limitations on produced

water associated with oil and gasextraction, a database was developedthat defined:

* Industry profile data on the numberand type of platforms and producedwater discharge rates.

* Projected future production activity.* Produced water contaminant

effluent levels associated with BPTtreatment and with BAT/NSPStreatment options.

* Cost to implement the BAT/NSPStreatment technology options.

Using these data, regulatory optionswere evaluated to define the cost andpollutant removals associated withcompliance with the options definedearlier in section XII.

Two sets of treatment technologieswere considered as BAT/NSPS modeltechnologies: (1) Filtration andsubsequent discharge, and (2) filtrationfollowed by injection (or reinjection).Because calculations of cost/pollutantreductions on a platform-by-platformbasis were considered impractical froma data collection standpoint, theindustry was characterized as consistingof a platform population divided among"model platforms." These "modelplatforms" were considered typical ofthe industry and were differentiatedbased on the number of well slots on theplatform, and in the case of one wellplatform, there was also adifferentiation for those that pipe theproduced fluids (or water) to a centraloffshore or land-based locality forprocessing and/or treatment.

For each "model platform" it waspossible to predict the number ofproducing wells, the quantity ofproduced water generated (average andpeak flow), and the cost to implement aproduced water treatment system. Thus,by dividing the industry among these"model platforms," estimates of costsand pollutant reductions could bederived.

Contaminant removals weredetermined by comparing the estimatedeffluent levels after treatment by theBAT/NSPS treatment system (eitherfiltration or reinjection) versus theeffluent levels associated with a typicalBPT treatment (gas flotation or gravityseparation).

The cost to install a BAT/NSPStreatment system for each of the modelplatforms was estimated based on themaximum produced water flow rateover the life of the project and the costof a treatment system designed toprovide the needed capacity. Data weredeveloped for treatment systems capitaland annual costs over a range of flows,and the cost for each model platformwas determined by interpolating withinthese data.

The results of the analysis arepresented in Tables 18 for BAT and 19for NSPS. Data are presented on numberof platforms affected, capital, andannual compliance costs, and annualpollutant removals in terms ofconventional, metal, and organicpollutants.

TABLE 18.-SUMMARY OF IMPLEMENTATION COSTS AND CONTAMINANT REMOVAL FOR PRODUCED WATERS-BAT

No. of Annual cost Pollutant reduction Qb/yr)platforms Capital ($) ($/y) Conventional Metals Organics

Filter and discharge shallow;, BPT deep ......................................................... 1,309 172,850,302 44,248,123 11,006,000 249,000 510,000Zero discharge shallow; BPT deep .................................................................. 1,309 1,258,707,237 76,194,925 18,101,000 255,000 575,000Filter and discharge all .......................................................................... 2,260 423,510.006 104.287,634 34,605,000 831,000 1.626,000Zero discharge shallow;, filter deep .................................................................. 2,260 1,517,366.941 136,154,436 41,700,000 837.000 1,690,000Zero discharge .................................................... 2.260 2,358,304,406 160.668.900 58,693.000 850,000 1.829,000Filter and discharge 4 mile; BPT beyond ........................................................ 208 35,250,039 8.384.563 3,234,000 74,000 140,000

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TAB.E 19.-SUMMARY OF IMPLEMENTATION COSTS AND CONTAMINANT REMOVAL FOR PRODUCED WATERs-NSPS (. NCONSTRAINEDDEVELOPMENT)

No. of Annual cost Pollutant reduction (lb/yr)platforms Capital cost ($) ($/yr) Conventional Metals Organics

Filter and discharge shallow;, 8PT deep .............................................. 393 104,874,421 22,108,417 6,599,000 142,000 312,000Zero discharge shallow, BPT deep ................................................................ 393 607,540,177 35,937,583 10,894,000 145,000 346,000Filter and discharge all ........................................................................... 851 300,853,708 61,717,502 27,404,000 673,000 1,326,000Zero discharge shallow;, fifter deep .............................................................. 851 803,519,464 75,626,728 31,698,000 677,000 1,359,000Reinect all ......................................................................................................... 851 1,300,307,478 89,509,755 44,850,000 688,000 1.465,000Filter and discharge 4 mile; BPT beyond ........................................................ 162 63,827,101 12,696,327 6,362,449 136,751 276,393

XVI. Economic Analysis

A. IntroductionThe Agency's economic impact

assessment is presented in the"Economic Impact Analysis of ProposedEffluent Limitations Guidelines andStandards of Performance for theOffshore Oil and Gas Industry"(hereinafter, "EIA"). This report detailsthe investment and annualized costs forthe industry as a whole and the impactsof these costa on affected projects andon typical companies involved inoffshore oil and gas drilling andproduction. The report also estimatesthe economic effect of compliance costson production, Federal and Staterevenues and discusses the impact onthe balance of trade and inflation. Inthis report, as in the section following,unless otherwise indicated, all costs arein 1980 dollars.)

EPA has also conducted an analysisof the cost-effectiveness of alternativetreatment options. The results of thiscost-effectiveness analysis areexpressed in terms of the incrementalcosts per pound-equivalent. Pound-equivalents account for the differencesin toxicity among the pollutantsremoved. The number of pounds of apollutant removed by each option ismultiplied by a toxic weighting factor.The toxic weighting factor is derivedusing ambient water quality criteria andtoxicity values. The toxic weightingfactors are then standardized by relatingthem to a particular pollutant, in thiscase, copper. Cost-effectiveness iscalculated as the ratio of incrementalannualized costs of an option to theincremental pounds-equivalent removedby that option. This analysis, "Cost-Effectiveness Analysis of ProposedEffluent Limitations Guidelines andStandards of Performance for theOffshore Oil and Gas Industry"(hereinafter, "Cost-EffectivenessReport"), is included in the record of thisrulemaking. Copies of this report and ofthe Economic Impact Analysis citedabove may be obtained from theeconomic analysis staff. (See theADDRESSES section of today's notice.)

B. Costs and Economic Impacts

1. Basis of Analysis

The costs and economic impacts oftoday's proposed regulations cover twomajor waste streams: (1) Drilling fluidsand drill cuttings associated withdrilling operations; and (2) producedwaters associated with productionoperations. (Incremental treatdnentrequirements for miscellaneous wastestreams create little or no additionalcosts and so the impacts of those costsare not analyzed separately here.)

The economic analysis of drillingoperations is based on the averagenumber of exploratory, delineation anddevelopment wells that the Agencyestimates will be drilled each yearthrough the year 2000. Only a smallpercentage of those wells are estimatedto be BAT wells, i.e., wells drilled onexisting platforms. The cost ofcontrolling the pollution from drillingoperations is estimated to be the same,on a per well basis, for BAT and NSPSwells.

The economic analysis of productionoperations is based on the number ofoffshore platforms producing in 1986 andon the Agency's projections of thenumber of platforms to be built between1986 and the year 2000. By the year 2000,new source oil and gas development isexpected to be stabilized, i.e., in thatyear, the number of new platformsbeginning production should equal thenumber of obsolescent platforms beingretired.

The basis of the economic analysishas changed in part since the 1985proposal, in response to new data and tocomments received on that proposal andon the 1988 Notice of Data Availability.The changes include:

(1) Data from the MineralsManagement Service (NMS), are usedinstead of Department of Energy (DOE]data to estimate the number ofnewwells and platforms. MMS data are animprovement over DOE data becauseMMS data are regionalized and includeprojections beyond the year 2000.

(2) In the 1985 proposal, theprojections of the number and type of

offshore facilities were based on anexpected average price of $32 per barrelof oil (bbl) ($1,986). The currentprojections are based on an average of$21 per bbl with sensitivity analyses at$15 and $32 per bbl ($1,986).

(3) In response to comments on the1988 Notice, the Agency now includes aone-well model platform. One-wellplatforms comprise about 20 percent ofthe facilities in the Gulf of Mexico.(Previously, the Agency's smallestmodel facility was a four-well platform.)

(4) Treatment costs are nowregionalized. (Previously, only theeconomic impact models wereregionalized.)

(5) Costs and impacts for BAT andNSPS are now estimated from "current"as defined by the current regional permitrequirements. Previously, NSPS andBAT were defined as incremental toBPT, not current. This change onlyaffects the treatment requirements fordrilling fluids and drill cuttings; regionalpermits for produced water do notrequire controls above BPT.

(6) The estimated number of offshorewells and platforms (based on $21 perbbl) are presented below. Estimates ofconstrained development are presentedto reflect current constraints on leasingand drilling in the Pacific and the lack ofAtlantic development. Unconstraineddevelopment estimates assume noconstraints on Pacific drilling and someAtlantic drilling.

The following discussion of costs andeconomic impacts assumes $21 per bbl,constrained development, and forproduced water, membrane filtration.The EIA and Cost-Effectiveness Repoi tsalso include sensitivity analyses of costsand impacts based on $15 and $32 perbbl, unconstrained development, andgranular filtration.

Assuming $21 per bbl the Agent.estimates:

Wells Drilled, NSPS:-759 per year, Constrained

Development;-980 per year, Unconstrained

Development.

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These well counts presented as NSPSare the total wells drilled during theperiod 1986 to 2000 divided by 15 yearsto give the annual average number ofwells drilled. The Agency does not havedata on which to base a precise estimateof the number of wells drilled onexisting platforms. However, the Agencyestimates that with restricteddevelopment about I percent of thewells drilled will, in fact, be BAT wellsdrilled on existing platforms. Typically,these BAT wells will be on the largerplatforms that have not completed theirdrilling program when this regulationgoes into effect. The drilling of BATwells will, therefore, be concentrated inthe first years after promulgation of thisregulation as the larger existingplatforms complete multiple-yeardrilling programs. As a result, most ofthe cost for these BAT wells will beincurred in the first years after theregulation goes into effect. The numberof BAT wells drilled will be highest inthe first year after the regulation andwill decline thereafter. Five years afterthe regulation goes into effect, few or noBAT wells will be drilled.

The Agency's estimates of totalplatforms are as follows:

Platforms, NSPS:-766 total, 1986-2000, Constrained

Development;-851 total, 1986-2000, Unconstrained

Development;Platforms, BAT: 2260.

Note that the number of platforms aretotal currently producing and the totalprojected to be installed during theperiod 1986 to 2000 while the number ofwells drilled is presented as annualaverage.

The number of offshore wells drilledannually that are within four miles ofshore and, therefore, will be affected bythe proposed zero discharge option areas follows:

Wells Drilled, NSPA:-81 (11 percent of 759), Constrained

Development;-152 (16 percent of 980), Unconstrained

Development.As explained above, the only site of

BAT wells would be on the largerplatforms, and, under constraineddevelopment, few of the larger platformsare within four miles of shore. Underconstrained development, the Agencyestimates that, at most, only a totalnumber of 100 BAT wells will be drilledwithin four miles of shore during theperiod 1986-2000.

The number of platforms within fourmiles of shore which are assumed tofilter prior to discharge to meet theproposed limitations on producedwaters are as follows:

Platforms, NSPA:-142 (19 percent of 766), 1986-2000,

Constrained Development;-162 (19 percent of 851), 1986-2000,

Unconstrained DevelopmentPlatforms, BAT: 208 (9 percent of

2260).

2. Total Costs and Impacts of ProposedRegulations

The combined annualized cost of thepreferred options proposed today forBCT, BAT and NSPS for both majorwaste streams is $54 to $80 million. (Thelower total costs reflect constraineddevelopment; the higher cost,unconstrained development of offshoreenergy resources.) For purposes ofestimating costs and impacts, zerodischarge for drilling fluids and drillcuttings, is assumed to be achieved bybarging. For produced water, zerodischarge is assumed to be achieved byreinjection and the limitations greaterthan BPT but less stringent than zerodischarge are assumed to be achievedby membrane filtration prior todischarge. The capital investment for theproposed requirements is limited toproduced water control. (No capitalinvestment is associated with thebarging of fluids and cuttings. Barging,land transportation and disposal is aservice supplied to the oil and gascompanies that are drilling offshorewells.) Total capital investment for thepreferred BAT option for producedwater is $35 million. Total capitalinvestment for the preferred NSPSrequirement for produced water is $64million.

The combined impact of the preferredoptions for drilling fluids anddrill cuttings and for produced waterwould reduce the working capital of atypical major offshore oil and gascompany by 0.2 percent and the workingcapital of a typical independentcompany by 1.9 percent. (Workingcapital is the parameter most sensitiveto increased costs.)

The potential loss In the present valueof future production of oil and gas as aresult of the preferred options isminimal. The preferred option fordrilling fluids and drill cuttings has noimpact on production. The preferredBAT and NSPS options for control ofproduced water is projected to result ina potential loss of 2 million barrels of oilequivalent (BOE) due to premature shutdowns of wells. (BOE is a standardmeasure of energy-equivalent.) The shutdowns are projected to occur becausethe regulation increases the cost ofoption and shortens the economic life ofsome platforms. This loss represents asmall percentage (0.02 percent) of 11.7

billion BOE, the present value ofoffshore production during the period1986-2000.

The preferred options potentiallycould result in an $50 million loss tofederal revenues (through tax effectsand lower lease bids) and a $3 millionloss to state revenues (through lowerlease bids). The impact of this potentialloss is minimal, representing, forexample, less than 0.01 percent of totalstate revenues in Texas. Furthermore,these losses are only potential:companies may not choose to recoup allthe cost increase from the proposedregulation through lower lease bids. Iflease bids are too low, companies mightnot win the lease. Under thesecircumstances, companies may absorbthe cost increase through reductions inprofits.

The proposed regulations are notexpected to impact energy prices,inflation, employment or internationaltrade. The preferred options may, infact, lead to temporary positive impactson the offshore service industry due tothe need to retrofit existing facilitieswith filtration equipment. The Agencyfinds the costs of the proposed BAT andNSPS regulations to be economicallyachievable for the oil and gas industry.

3. Economic MethodologyThe Agency used a net present value

analysis to calculate whether offshoredevelopment operations could remainprofitable after regulatory costs wereincurred. First, costs and revenues wereprojected over the life of the modelproject based on the current, orbaseline, requirements. (The life of aproject varies among the modelprojects.) Then the regulatory costs wereadded to those baseline costs todetermine if the model platformsremained profitable. EPA used 34 modelplatforms to represent the diversity inoffshore platform size (i.e., the numberof well slots per platform), geographiclocation (Gulf of Mexico, Pacific,Alaska, and Atlantic coasts), andproduction type (oil only, gas only orboth). Distinct technical and economiccharacteristics for each model weredeveloped. Costs included in thebaseline were those associated withexploration, delineation, developmentproduction operations, as well as thecosts needed to meet current regionalpermit requirements.

To assess the impact on offshore oiland gas companies operating in theoffshore area, the Agency developedtwo representative company financialprofiles: One for major integratedcompanies and one for independents.Pre- and post-regulation balance sheets

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were developed and the effect ofregulatory costs on the typical majorand on the typical independentcompanies was then analyzed.

4. Costs and Impacts of BestConventional Pollutant ControlTechnology

Section XII presents proposed BCroptions. For drilling fluids and drillcuttings, the preferred option requireszero discharge for wells at four miles orless from the shore. For purposes ofcosting, this requirement is assumed tobe achieved by barging of fluids andcuttings for transportation and disposalon land. On a per-well basis, bargingcosts are the same for BCT, BAT, andNSPS. The preferred options for BCT,BAT and NSPS all require zerodischarge for wells drilled within fourmiles of shore; costing for BCT. BAT,and NSPS all assumed, for purposes ofcosting, that zero discharge would beachieved by barging. For wells drilledbeyond four miles of shore, BAT andNSPS costs include monitoring for andcontrol of toxics; BCT costs do not. Asexplained above, at most a total of 100BAT wells are projected to be drilled onthe existing platforms that are four orless miles from shore. Thus, for thepreferred BCT option, at most, total (notannualized) BCT costs would not exceed$350 million for the period 1986 to 2000.Most of these costs would be incurred inthe first years after the regulation goesinto effect. On a per-well or per-projected basis, BCT costs equal BAT/NSPS costs. According to the Agency'sanalysis, BAT/NSPS costs areeconomically achievable. Consequently,the BCT costs are also economicallyachievable.

As discussed in section XHI above, forproduced water, BCT equals BPT.Therefore, for produced water, there areno incremental costs for BCT and noeconomic impacts.

5. Costs and Impacts of Best AchievableTechnology

a. Drilling Fluids and Drill Cuttings.The Agency estimates that during theperiod 1980-2000, at most, only a total of100 wells drilled offshore will be onexisting platforms located within fourmiles of shore and thus subject to theproposed BAT regulation of zerodischarge. For purposes of costing andestimating impacts, wells required tomeet zero discharge are assumed tobarge fluids and cuttings to shore; wellsbeyond four miles are to meet thelimitations described in section XII.A2above (the 1/1 option). On a per-well-basis, the average cost of barging fiom aBAT well drilled on an existing platformis expected to be equal to the cost of

barging from an NSPS well, or anaverage of $350 thousand per welldrilled (assuming restricteddevelopment). This per-well costincludes barging, land transportation.and land disposal of fluids and cuttingsfrom wells within four miles from shore.For wells drilled beyond four miles ofshore, the costs of compliance includemonitoring, the cost of substitutingmineral oil for diesel oil for spotting andlubricity and the cost of "clean" bariteto meet the limitations on cadmium andmercury in the drilling fluids. The costsof the preferred option are incrementalto current permit requirements.

Most of the wells drilled on existingplatforms will be on the larger platforms(i.e., those with more well-slots). Theselarge platforms will not have completedtheir drilling programs at the time theregulation goes into effect, but they willdo so in the first few years of theregulation. Therefore, the economicImpact of BAT regulations on drillingfluids and drill cuttings will beconcentrated in the first five or so yearsafter the regulation goes into effect.After five years, few, if any. wells willbe drilled on existing platforms.

No capital investment will be neededto meet the preferred limitations ondrilling fluids and drill cuttings becauseoil companies that drill offshoretypically do not purchase barges, butinstead contract for that service. In thisanalysis, BAT costs are included in thetotal annualized NSPS. Total (i.e., notannualized) BAT costs of $350 millionare based on an estimated total of 100wells will be drilled in the first fiveyears after this regulation goes intoeffect.

According to the Agency's analysis,the economic impact of the proposedBAT option for drilling fluids and drillcuttings is the same as the impact of theNSPS, which are discussed below. Thecosts of the proposed BAT regulation ofdrilling fluids and drill cuttings areeconomically achievable.

b. Produced Waters. The Agencyestimates that 2,260 offshore platformscurrently are producing either oil or gasor both. Of these, 208 platforms arewithin four miles of shore and therefore,under the preferred option, will besubject to limitations beyond BPT forproduced waters (as described insections XII.C.1 and XIII.C.2, above). Forpurposes of estimating costs andimpacts, the Agency assumed thelimitations on existing platforms withinfour miles of shore would be achievedby membrane filtration of producedwater prior to discharge. Platformsbeyond four miles would be subject toBPT.

Total capital costs of the BATpreferred option are estimated to be $35million. Annual operating andmaintenance costs of $8 million includemonitoring at all platforms and filtrationof produced waters at those platformswithin four miles of shore. Theannualized incremental costs of the BAToptions considered for produced waterrange between $13 million and $491million. The annualized incremental costof the proposed option is $13 million.

The EIA includes impacts of theoptions considered on each type ofmodel platform. Selected impacts arepresented here- Impacts on the Gulf-12platform are typical of impacts on theindustry; impacts on the Gulf one-wellmodel platforms are presented herebecause these small platforms are mostsensitive to impacts of the regulation.

For existing oil and gas Gulf-12platforms four miles or less from shore,the BAT preferred (filtration) optionincreases the corporate cost per BOE 1.6percent and decreases the net presentvalue of the project 4.7 percent. Theplatform's production is decreased 11percent because it would shutdown ayear early.

For existing one-well platforms in theGulf of Mexico that produce oil and gasand have their own productionequipment, the BAT preferred optionincreases the corporate cost per BOE 14percent and decreases the net presentvalue of the project 27 percent. Theplatform's production is decreased 22percent because it would shutdown twoyears early. (See impacts on Gulf 1B's inthe EIA.)

The preferred BAT option would havevirtually no impact on the workingcapital of a typical major company thatis involved in offshore energyproduction and would reduce theworking capital of a typical independentcompany by 0.5 percent. According tothe Agency's analysis, the preferredoption would have no effect on oil andgas prices, employment, or internationaltrade. The Agency finds the costs of thepreferred BAT option for control ofproduced waters to be economicallyachievable for the oil and gas industry.6. Costs and Impacts of New SourcePerformance Standards

a. Drilling Fluids and Drill Cuttings.Of the 759 exploratory, delineation, anddevelopment wells projected to bedrilled each year 1986-2000 underconstrained offshore development. 81(or 11 percentl will be on new platformsand thus subject to the NSPS proposedoption. For purposes of costing andimpacts, the Agency assumes wellsdrilled within four miles of shore will

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meet the zero discharge limitation bybarging, wells drilled beyond four mileswill meet limitations describedpreviously as the "1/i" option.

The total annualized incrementalcosts of regulating drilling fluids anddrill cuttings range between $0.8 millionand $211 million. The annualizedincremental cost of the preferred optionis $29.5 million. (As explained above, forfluids and cuttings, these costs areoperating and maintenance costs,including monitoring; there are nocapital costs associated with anyoptions considered for these wastestreams.)

For new oil and gas wells drilled onGulf-12 platforms four miles or less fromshore, the preferred NSPS optionincreases the corporate cost per BOE 0.2percent and decreases the net presentvalue of the project 0.9 percent. For newoil and gas wells drilled in the Gulf onone-well platforms that have their ownproduction equipment, option increasesthe corporate cost per BOE 0.7 percentand decreases the net present value ofthe project 11.5 percent. (See impacts onthe Gulf IB's in the EIA.)

None of the options considered fordrilling fluids and drill cuttings have anadverse impact cm production.

The preferred option would reduce theworking capital of a typical majorcompany that is involved in offshoreenergy production by 0.1 percent and theworking capital of a typical independentcompany by 1.0 percent According tothe Agency's analysis, the preferredoption would have no effect on oil andgas prices, employment, or internationaltrade. The Agency finds the costs of thepreferred NSPS option for fluids andcuttings are economically achievable.

b. Produced Water. Of the 766platforms projected to be installedoffshore between 1986 and the year2000. assuming constrained offshoredevelopment, 142 are estimated to befour or less miles from shore andtherefore, under the preferred option,will be subject to limitations beyondBPT for produced water (as described insections XII.C.1 and XM.C.2, above). Forpurposes of estimating costs andimpacts, the Agency assumed thelimitations on new platforms within fourmiles of shore would be achieved bymembrane filtration of produced waterprior to discharge. Platforms beyondfour miles would be subject to BPT.

Total capital costs of the NSPSpreferred option are estimated to be $41million ($64 million for theunconstrained scenario). Annualoperating and maintenance costs of $8million ($13 million for theunconstrained scenario) includemonitoring at all platforms and filtration

of produced waters at those platformswithin four miles of shore. Theannualized incremental cost of the NSPSoptions considered for produced waterrange between $11 million and $158million. The annualized incrementalcosts of the preferred option is $11million ($17 million for theunconstrained scenario).

For new oil and gas Gulf-12 platformsfour miles or less from shore, thepreferred NSPS membrane filtrationoption increases the corporate cost perBOE 0.6 percent and decreases the netpresent value of the project 2.2 percent.The preferred NSPS option for producedwater has no adverse impact onproduction from Gulf-12 platforms.(Production on most model platforms, infact, is not adversely impacted by NSPSfor produced waters.)

For the projected NSPS one-wellplatforms in the Gulf that produce oiland gas and have their own productionequipment, the preferred membranefiltration option increases the corporatecost per BOE by 2.7 percent anddecreases the present value of theproject by 69 percent. Production onthese platforms would decrease 10percent because they would shut downtwo years earlier than normal.

The preferred NSPS option forproduced water would have virtually noimpact on the working capital of atypical major company that is involvedin offshore energy production and wouldreduce the working capital of a typicalindependent by only 0.4 percent.According to the Agency's analysis, thepreferred option would have no effecton oil and gas prices, employment, orinternational trade. The Agency findsthe costs of the proposed NSPSregulation of produced waters to beeconomically achievable for the oil andgas industry.

C. Cost-Effectiveness Analysis

In addition to the foregoing analyses,the Agency has performed a cost-effectiveness analysis for each of theproposed options. According to theAgency's standard procedures forcalculating cost-effectiveness, all theoptions considered for each wastestream have been ranked in order ofincreasing pounds-equivalent (PE)removed. The pounds-equivalentremoved for each option consideredwere calculated by weighting thenumber of pounds of each pollutantremoved for each option by the relativetoxic weighting factor for each pollutant.The use of "pounds-equivalent" givesrelatively more weight to removal ofmore highly toxic pollutants. Thus for agiven expenditure, the cost per pound-equivalent would be lower when a

highly toxic pollutant Is removed than ifa less toxic pollutant is removed. Costeffectiveness is calculated as the ratio ofthe incremental annual costs to theincremental pounds-equivalent removedfor each option. So that comparisons ofthe cost effectiveness among regulatedindustries may be made, annual costsfor all cost-effectiveness analyses arereported in 1981 dollars.

For the selected options (in $1981), theincremental cost effectiveness is $22 perpound-equivalent for drilling fluids anddrill cuttings; $60 per pound-equivalentfor produced waters, BAT, and $63 perpound-equivalent for produced waters,NSPS. The Cost-Effectiveness Report.which is available in the record of thisrulemaking, describes the costeffectiveness calculations in detail andpresents the pollutants included in thecost-effectiveness analysis, the toxicweights used for each pollutant, andsensitivity analyses for such variablesas unconstrained development,alternative energy values of $15 and $32per bbl, and use of granular filtration.

These cost-effectiveness values reflectthe Agency's standard cost-effectiveness methodology. In themajority of the Agency's effluentguideline regulations developed to date,the discharges have been to freshwaters (directly or indirectly viapublicly owned treatment works). In thiscase the discharges are to marinewaters. As described below in sectionXVII, the Agency has had somedifficulty assessing the benefits of thisregulation due to the nature of thewaters affected by discharges fromoffshore platforms. For this reason, theAgency is requesting commentconcerning the procedures that can beused to assess the value of controllingdischarges to these different waters forthe purposes of benefit analyses. (Seesection XIX of today's notice.)

D. Regulatory Flexibility Analysis

The Regulatory Flexibility Act of 1980,Public Law 96-354, requires that theAgency prepare an initial RegulatoryFlexibility Analysis (RFA) for allproposed regulations that have asignificant impact on a substantialnumber of small entities. This analysismay be done in conjunction with or as apart of any other analysis conducted bythe Agency. The purpose of the Act is toensure that, while achieving theAgency's statutory goals, the Agency'sregulations do not impose unnecessarycosts on small entities.

The economic impact analysisdescribed above indicates that theexpenditures necessary to meei theproposed limitations and guidelines for

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the offshore oil and gas industry will befinanced by major and independent oilcompanies. These are not "smallbusinesses" by any standard.Additionally, the analysis hasdetermined that none of the companiesdirectly affected by this regulation aresmall businesses. Therefore, a formalRegulatory Flexibility Analysis is notrequired.E. Paperwork Reduction Act

This proposed rule will impose noincrease in reporting or recordkeepingburden to respondents as covered underthe provisions of the PaperworkReduction Act, 44 U.S.C. 3501 et seq. Theproposed rule contains no informationcollection provisions.

XVII. Executive Order 12291Executive Order 12291 requires the

Environmental Protection Agency andother agencies to perform a RegulatoryImpact Analysis (RIA) of majorregulations. Major rules are those whichimpose an annual cost on the economyof $100 million or more or meet certainother economic impact criteria. The RIAprepared by EPA for this rule may beobtained at the address listed at thebeginning of the preamble. This RIA wassubmitted to the Office of Managementand Budget (OMB) for review, asrequired by Executive Order 12291.

Three types of benefits were analyzedin this RIA: Quantified and monetizedbenefits; quantified and non-monetizedbenefits; non-quantified and non-monetized benefits. The combinedmonetized benefits of regulating drillingfluids, drill cuttings, and produced waterin the offshore subcategory of the oiland gas extraction industry were foundto be reasonably commensurate withtheir costs. The total monetized benefitsfor the selected options (1986 dollars:Gulf of Mexico only) range from $13.4 to$65.2 million annually. The totalannualized BAT and NSPS costs (1986dollars; Gulf of Mexico only) range from$47.4 to $67.6 million for drilling fluids,drill cuttings, and produced water. (Theprimary difference in the cost rangereflects membrane filtration at the lowend and granular filtration at the highend.)

Monetized benefits were based solelyon health-related impacts. Benefitsassociated with regulating drilling fluidsand cuttings greatly predominated overthose associated with regulatingproduced water, for drilling fluids andcuttings, lead-relited health benefitsgreatly predominated over carcinogen-related health benefits. The quantified,non-monetized benefits assessmentincluded a review of case studies ofenvironmental impacts of drilling fluids

and cuttings and produced water thatdocumented adverse chemical andbiological impacts result fromdischarges of these wastes. In addition,a water quality analysis was preparedthat for selected options projecteddecreases in the number of pollutantsexhibiting water quality criteriaexceedances as well as the magnitude ofthese exceedances.

The RIA contains an analysis of theeffect of the proposed regulations formajor waste streams from offshore oiland gas exploration (i.e., drilling mudsand cuttings), and production activities(i.e., produced water) on existing marinewater quality. The analysis for thesewaste streams has two parts.

The first part of the RIA summarizescase studies of local impacts found nearoil and gas platforms located in the Gulfof Mexico, in water off California andAlaska. A comprehensive review ofavailable data (over 800 references, plusEPA's Ocean Data Evaluation System(ODES) database) shows documentedlocal impacts for drilling muds andcuttings (18 case studies) and forproduced water discharges (seven casestudies). Widespread marine impactswere not well documented.

Discharged muds and cuttings areshown to cause contamination ofsediments with heavy metals andhydrocarbons known to be present inthese discharges up to 4,000 meters fromthe platforms. Other documentedimpacts include declined abundance inbenthic species (up to 1000 m from theplatform), reduced bryozoan coverage(within 2000 m of discharge), alteredbenthic communities (up to 300 m fromplatform), bioaccumulation of heavymetals known to be present in drillingmuds and cuttings by benthic organisms,complete elimination of seagrass (within300 m of discharge) inhibited growth ofseagrass (up to 3,700 m distance) anddecreased coral coverage.

Produced water discharges are shownto cause contamination of sedimentswith polynuclear aromatic hydrocarbons(PAH) up to 3000 m from the platforms.Other significant impacts includecomplete elimination of benthicorganisms up to 400 m from the platform,depressed abundance of benthic speciesup to 5000 m, and alteration of benthiccommunities (mostly towardopportunistic species).

The second part of the RIA usesmodeling to project water qualityimpacts /benefits for existing and new-Outer Continental Shelf (OCS) oil andgas platforms in the Gulf of Mexico. Thecurrent "baseline" and considered BATand NSPS options are assessed. EPA'spublished marine water quality criteriaare used to assess water quality

impacts. The human health risk/benefitsfrom consumption of fish and shellfishexposed to the OCS oil and gas platformdischarges in the Gulf of Mexico areaare also assessed. The Gulf of Mexico-was selected as a case study areabecause of its majority of the offshoreoil and gas exploration and productionactivities, as well as its extensive andabundant commercial and recreationalfishing activities.

The RIA attempts to monetize thespecific health and environmentalbenefits that may result from theproposed regulations. However, theextent of dilution afforded by the marineenvironment resulted in modeledconcentrations for the selected averageindustry-wide pollutants so low thatunder current regulatory controls nodirect quantifiable impacts on the Gulfof Mexico fishery can be attributed tothe platform-related discharges.Predictions could not be made toquantify direct impacts of currentdischarges and proposed regulations on:composition and abundance of fin fishand shellfish population; recreationalfishing and other recreational activities;commercial fishing; or nonuse benefits.Therefore, the RIA focuses almostexclusively on the benefits associatedwith human health risk reductionthrough reduced concentration ofplatform-related pollutants in selectedrecreational fish species andcommercial shrimp. Both carcinogenicand systemic human toxicants areconsidered. These quantified andmonetized incremental benefits arecompared to the annualized incrementalcost in the Gulf of Mexico for the BATand NSPS control options underconsideration.

A. Produced Water

Water quality impacts are projectedfor granular filtration on the basis ofeight pollutants representing averageindustry-wide production discharges; formembrane filtration, impacts areprojected on the basis of 23 pollutants.The membrane filtration analysisproject two pollutants (arsenic andbis(2-ethylhexyl) phthalate) exceedinghuman health criteria for fishconsumption. Granular filtrationanalysis projects that one pollutant(bis(2-ethylhexyl) phthalate) exceedshuman health criteria. None of thepollutants modeled exceeds marineaquatic life criteria at the currentdischarge (BPT). The preferred BA'i andNSPS options will not completelyeliminate these human health criteriaexceedances but will reduce themagnitude of the impact.

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Determination of the cost/benefitanalysis for both the membrane andgranular filtration technologies has beenrestricted by the limited amount ofpublished quantifiable human healthdata for the majority of pollutants ofconcern. As a result, human healthbenefits have been underestimated. Thecost/benefit analysis for membranefiltration was limited to analysis of threepollutants (arsenic, benzene, and bis(2-ethyihexyl) phthalate), while thegranular filtration analysis includedonly two pollutants {benzene and bis(2-ethylhexyl) phthalhte).

Based on these limitations in theanalysis, human health benefits areestimated to range between $1,000 and$6,000 per year for the proposed BAToption using membrane filtration in the

Gulf of Mexico, compared with aprojected incremental annualized cost of$9 million for membrane filtration in theGulf. These monetized benefits arebased on the average risk reductionassociated with the consumption ofplatform-contaminated fish and shrimpfor the three carcinogens noted above.The risk reduction projections arederived from flow-weighted industry-wide average pollutant concentrations.Monetized human health benefits due toremovals of the two carcinogensassociated with the proposed BAToption using granular filtration rangebetween $2,000 and $9,000 per year inthe Gulf of Mexico. The risk reductionprojections for granular filtration arebased on concentrations for individualproduction groups (oil only, gas only, oil

and gas). The annualized costs for theproposed BAT option are $24 million forthe Gulf. The estimated annualizedhuman health benefits in the Gulf ofMexico for the proposed NSPS option(based on the same pollutants andmethodology) are estimated to rangefrom $300 to $2,000 for membranefiltration and from $200 to $1,000 forgranular filtration. These NSPS benefitscompare with NSPS annualized costs forthe Gulf of $9 million (membranefiltration] and $14 million (granularfiltration) (1986 dollars) (Table 20). Anadditional reduction in human healthrisk due to subsistence fishing near theoil and gas platforms in the Gulf ofMexico region is also anticipated butcould not be quantified in the RIA.

TABLE 20-INCREMENTAL ANNUALIZED BENEFITS AND COSTS FOR PRODUCED WATER BAT/NSPS OPTIONS

[Thousands of 1986 dollars per year Gulf of Mexico only]

Produced water BAT options Produced water NSPS options

Regulatry.option Incremental benefits Incremental costs Incremental benefits Incremental costs

Membrane Granular Membrane Granular Membrane Granular Membrane Granularfilter filter filter filter filter filter filter filter

BPT all ......... .... 0 0 0 0 0 0 0 0Four mile filter, BPT beyond* ................ .............. 1-8 2-9 8,787 24,287 0.3-2 0.2-1 9,079 13,842Filter shallow, OPT deep ......................................... N/A 4-22 59,378 N/A N/A 3-13 26,236 N/AFilter and discharge all ....... ... N/A 6-31 139,609 438,067 N/A 3-16 56,558 86,845Zero dischere haflow, BPT dee NIA 5-23 247,095 N/A NIA 3-14 81,398 NIAZero discharge shallow, filter deep_ .. _ N/A 6-31 327.326 N/A N/A 3-17 111,629 N/AZero discharge all ................................................. N/A 6-32 458,736 776,772 N/A 3-17 145,572 186,608

Not":1. All incremental values reltive to current (BPT) treatment level.2. tncremental benefits reflect monetized health benefits only. Membrane filter benefit projections derived from industry-wide flow-weighted averages for 3

carcinogena e not directly comparable to granular filter projectione based on individual production groups for 2 carcinogens.*Preferred option in today's notice.N/A: Not Available.

Neither analysis for granular ormembrane filtration considers impactsof various additives, especially biocides,due to the lack of specific data on theactual use/discharge of thesecomponents by the industry. EPAidentified only a limited number of thebiocides as actually used by theindustry. Many of the biocidesregistered by EPA's Office of Pesticidesand Toxic Substances, or identified asused by the industry, are highly toxic tomarine aquatic life, and others arecarcinogenic. These pollutants maycause adverse impacts on the marineenvironment and/or human healththrough fish consumption if dischargedin sufficient quantities. EPA expects tocollect additional pollutant data, anddata on actual use/discharge of biocidesand other toxic additives, prior to finalpromulgation to more preciselycharacterize average industry-widedischarges. EPA is also soliciting newinformation on produced water

characteristics, and environmentalimpacts associated with discharges ofthese wastes into the marineenvironmenL

The impacts of radioactive pollutantsin produced water (e.g., radium-226 andradium-228) are not evaluated for eitherfiltration technology although they havebeen identified in produced waters inthe Gulf of Mexico region. Theseradioactive pollutants are known humancarcinogens and are known tobioaccumulate in fish and shellfish.These pollutants have a potential tocause human health impacts throughfish consumption. Recent data from acoastal Louisiana study show thesepollutants to accumulate in thesediments, as well as caged oysters.

However, data are lacking on the fateand impacts of these pollutants in theoffshore environment which precludes acomplete assessment of potential humanhealth risks and projected benefitsassociated with controlling the

discharge of these pollutants at thistime. EPA is concerned about theseimpacts, however, and expects to collectadditional data on discharges ofradioactive pollutants by the offshoresubcategory, and on the removalefficiency of the existing controltechnologies prior to final promulgation.This new information will be used toproject potential environmental impactsand regulatory benefits for the final RIA.EPA is also soliciting information ondischarge levels of these pollutants,their fate in the marine environment, aswell as data on the knownenvironmental impacts in the offshoreenvironment.

B. Drilling Fluids and Drill Cuttings

Water quality impacts/benefits areprojected for eight pollutantsrepresenting average industry-widedrilling discharges. The analysisindicates that two pollutants (lead andmercury) exceed marine aquatic life

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criteria, and two pollutants (arsenic andmercury) exceed human health criteriafor fish consumption under currentdischarge conditions. The preferredBAT/NSPS option will eliminate theseviolations from the moreenvironmentally sensitive shallow waterareas, as well as reduce the number ofpollutants with projected exceedancesto one (mercury) for marine aquatic lifecriteria and one (arsenic) for humanhealth criteria for fish consumption.

The estimated human health benefitsfor the preferred BAT/NSPS optionbased on the combined quantifiedaverage risk reduction associated withconsumption of platform contaminatedfish and shrimp by lead and arsenic arein the range of $13.4 million to $65.2million, versus a projected incrementalannualized cost of $29.5 million (1986dollars). (Table 21) An additionalreduction in human health risk due tothe subsistence fishing near theplatforms in the Gulf of Mexico region isalso anticipated but cannot bequantified by the preliminary RIA.

TABLE 21-INCREMENTAL ANNUALIZEDBENEFITS AND COSTS FOR DRILLINGFLUIDS AND CUTTINGS BAT/NSPS OP-TIONS

[thousands of 1986 dollars per year, Gulf of Mexicoonly]

Regulatory Incremental Incrementaloption benefit cost

5/3 All I .............. N/C 78711/1 All ................ 13,431-65,184- 8,466

65,381Zero discharge

4 miles; 5/3beyond ............. 12,396-60,381 22,493

Zero discharge4 miles; 1/1beyond I ......... 13,341-65,184 29,500

Zero dischargeshallow; 5/3deep ................ 12,584-60,856 81,119

Zero dischargeshallow;, 1/1deep ................ 13,431-65,185 86,279

Zero dischargeall .................. 13,432-65,188 211,859

NOTES1. All incremental values relative to current treat-

ment level.

2. Incremental benefits reflect monetized benefitsonly.

3. Current treatment assumed to be equivalent to"5/3 All" option for analytic purposes.

I Current treatment assumed to be equivalent to"5/3 All" option for analytic purposes. Incrementalcosts incurred are due to monitoring requirements.

2 Preferred option in today's notice.N/C: Not Calcu!ated.

The water quality analysis and cost/benefit analysis for drilling fluids andcuttings underestimates the benefitsderived from the proposed regulation byconsidering impacts of only eightpollutants to represent average industry-wide drilling discharges. Pollutantsdetected only in limited number ofsamples, are not considered to beindustry-wide pollutants, and aretherefore not considered in thepreliminary RIA. Some of these non-considered pollutants are toxic to themarine life and/or human health andmay cause local chronic or sub-chronicmarine life or human health impactsaround the platforms if discharged insufficient quantities. EPA expects tocollect additional pollutant data prior tofinal promulgation to more preciselycharacterize average industry-widedischarges. These pollutants will beincluded in water quality and cost/benefit analysis for the finalpromulgation. EPA is also soliciting newinformation on drilling wastecharacteristics, and environmentalimpacts associated with discharges ofthese waste streams into the marineenvironment.

XVIII. Non-Water QualityEnvironmental Impacts and OtherFactors

A. Non-Water Quality EnvironmentalImpacts

The elimination or reduction of oneform of pollution may aggravate otherenvironmental problems. Therefore,sections 304(b) and 306 of the Actrequire the Agency to consider the non-water quality environmental impacts(including energy requirements) ofcertain regulations. In compliance withthese provisions, the Agency hasevaluated the effect of the options beingconsidered for the proposed regulationson air pollution, solid waste generation

and management, and energyconsumption.

The following is a description of thenon-water quality environmentalimpacts associated with the optionsconsidered for today's proposedregulations and a summary of the resultsof the evaluations identifying theestimated levels and impacts for each ofthe considered options.

1. Energy Requirements and AirEmissions

Some of the proposed options areestimated to result in the generation ofsignificant amounts of air emissions andthe use of significant amounts ofadditional energy to comply with theadditional treatment and controlrequirements for drilling fluids and drillcuttings and produced water.

Energy requirements and resulting airemissions for the control optionsconsidered by EPA are presented inTable 22 for drilling wastes and in Table23 for the production wastes. Estimatesare incremented to BPT. Thus, 1, rexample, the "5/3 All" estimates shouldapproximate the energy requirementsand air emissions associated with therequirements of existing permits.Presently, there are no nationalstandards that directly regulateemissions from offshore oil and gasfacilities. However, pursuant to theClean Air Act Amendments of 1990,specific requirements are to be issuedwithin a year controlling air emissionsfrom OCS sources located offshore ofthe states along the Pacific, Arctic, andAtlantic coasts and along the Gulf coastoff the state of Florida. The majority ofoffshore oil and gas activities, which arein the Gulf of Mexico offshore ofLouisiana, Texas, etc., are not includedin the coverage of these upcomingrequirements. Sources of air pollutionfrom offshore activities include leaks,oil-water separators, dissolved airflotation units, painting apparatus, andstorage tanks, but more significantlydiesel or gas engines for generatingpower, either on the structures or for thepurpose of transportation to and fromthe structures.

TABLE 22-NON-WATER QUALITY ENVIRONMENTAL IMPACTS: UNCONSTRAINED DEVELOPMENT

Volume of barged Air emissions Fuel requirements

I waste (bbl/yr) I (short tons/yr) (BOE/yr)

5/3 all structures .......................................1/1 aU structrues .......................................Four mile zero discharge; 5/3 beyondFour mile zero discharge; 1/1 beyondZero discharge shallow; 5/3 deep ..........Zero discharge shallow; 1/1 deep ..........

Drilling Fluids and Cuttings552,000552.000

1,596,0001,596,0002,746,0002,746,000

79,51779,517

173,360173,360293,535293,535

....................... I ........................................................................................

................................................................................................................

...............................................................................................................

................................................. I ..............................................................

................................................................................................................

................................................................................................................

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TABLE 22-NON-WATER QUALITY ENVIRONMENTAL IMPACTS: UNCONSTRAINED DEVELOPMENT-Continued

For drilling fluids and drill cuttings,the only technology under considerationthat has significant energy consumptionimpact is the use of barges to transportwaste solids to shore and landtransportation of land disposal of thesewastes. Table 22 summarizes the fuelrequirements and resulting air emissionsfor this option.

Air emissions are calculated for sulfurdioxide (SO2), carbon dioxide (CO2),hydrocarbons (HC), and nitrogen oxides(NOJ. These calculations areincremental to BPT and assume all oil-based drilling fluids and drill cuttings

have either been substituted for or arebeing disposed of by shipment to land.The methodology used for the fuelconsumption and emission calculationsare described in the developmentdocuments.

Materials barged for the "5/3 All" andthe "1/1 All" options are those thatwould normally require barging (i.e., donot comply with the required effluentlimits). As can be seen by the table, azero discharge requirement, whetherapplicable to all of the structures or tothose structures located in shallowwater depth, significantly increases the

amount of barged material and resultingfuel consumption and air emissions.

The non-water quality environmentalimpacts related to the produced wateroptions are shown in Table 23. Theopertions requireing zero discharge forproduced water greatly increase airemissions and fueld requirements ascompared to those of the filtration anddischarge options. This is due primarilyto the energy required of reinjectionequality in order to pumpt fluids intoformations.

TABLE 23-NON-WATER QUALITY ENVIRONMENTAL IMPACTS: UNCONSTRAINED DEVELOPMENT

[Produced Water]

Fuel requirements (BOE/ Total emissions (shortOption year) tons/year)

BAT NSPS BAT NSPS

Filter and discharge; 4 miles; BPT deep ...................................................................................................................... 5,490 10,920 9 18Filter shallow, BPT deep ....................................................................... ............. 190 11,440 32 19Filter and,discharge; all ................................................................................................................................................. 58,980 46,650 97 77Zero discharge shallow;, BPT deep ................................................................................................................................ 709,510 422,540 1,178 702Zero discharge shallow;, filter deep ................................................................................................................................ 750,000 457,750 1,244 760Zero discharge; all ......................... ............................................................................. .... 2,179,580 1,718,310 3,619 2,853

BOE: barrel of oil equivalent.

Air emissions calculated for producedwaters include particulates in additionto NO., CO, and SO2. These arepollutants associated with gas turbineoperation. Energy requirements forreinjection were based on an injectionpressures of 1,800 psi and the energyderived from a natural gas turbine. An80 percent motor efficiency and a 20percent energy conversion efficiencywere assumed. The same basis wasused for the power requirements for thefiltration option calculations, exceptpressurization to 50 psi was assumed.

2. Solid Waste Generation

The Agency evaluated the impacts ofsolid waste generation and disposal forthe options considered in thisrulemaking. The Agency concluded thatthere is adequate onshore capacity forthe disposal of the amounts of drillingwastes (drilling fluids and cuttings)estimated to be generated by thepreferred regulatory option (4 Mile; 1/1deep). The following is a summary of theAgency's findings in this regard.

The regulatory options described intoday's notice will not cause thegeneration of additional solids as aresult of the treatment technology.However, some of the options--particularly those requiring zerodischarge for drilling fluids andcuttings-would require disposal of thesolids associated with waste materials.In particular, used drilling fluids andcuttings contain relatively high levels ofsolids, and considerable volumes aregenerated which would be disposedonshore under several of the regulatoryoptions presented in today's notice.

For example, under the optionrequiring zero discharge of drillingwastes from all new offshore wells, EPAestimates that approximately 8.2 millionbarrels per year of drilling fluids anddrill cuttings would be transported toshore for disposal. As indicated in Table22. this zero discharge option representsthe maximum amount of barged wastesrequired by any of the optionsconsidered in this rulemaking. This

volume of barged wastes may becompared to the Agency's estimates of361 million barrels per year of drillingwastes generated from the drilling ofonshore wells, including the "onshore"and "coastal" subcategories. See"Report to Congress: Management ofWastes from the Exploration,Development, and Production of CrudeOil, Natural Gas, and GeothermalEnergy," U.S. EPA, Office of SolidWaste, EPA/530-SW-88-003, December1987 (hereinafter "Report to Congress").The maximum barged volume ofapproximately 8.2 million barrels peryear represents about 2.3 percent of thevolume of all drilling wastes that aregenerated and disposed onshore.Likewise, Table 20 Indicates that theAgency's preferred regulatory option (4Mile; 1/1 deep) would require thetransport of approximately 1.6 millionbarrels per year of drilling waste toshore for disposal. This represents lessthan 0.5 percent of the volume of all the

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drilling wastes that are generated anddisposed onshore.

Those drilling wastes that aregenerated offshore and transported toshore for disposal under the preferredoption would be deposited in landdisposal units similar to those used tomanage a portion of onshore-generateddrilling wastes. These land disposalunits would generally be locatedrelatively near the coast where thewastes are brought to shore. While thereare currently no federal requirements forthe onshore disposal of drilling wastesunder the RCRA (see EPA's "RegulatoryDetermination for Oil and GasGeothermal Exploration, Developmentand Production Wastes" at 53 FR 25446).there are existing State programrequirements in the Gulf Coast andCalifornia Coast areas where the wasteswould be brought to shore. EPA isdeveloping a tailored program for themanagement of exploration andproduction wastes under RCRA SubtitleD.

As discussed in Section XIV oftoday's notice, the Agency did studythat availability of land disposalcapacity for drilling wastes that wouldbe transported to shore for disposalunder the regulatory options presentedin today's notice ("Onshore Disposal ofOffshore Drilling Waste-Capacity andCost of Onshore Disposal Facilities,"ERC Environmental and Energy ServicesCo. for U.S. EPA, January 1991). Thatstudy concluded that there is at least 45million barrels per year of available orprojected land disposal capacity fordrilling wastes beyond currentrequirements in the Gulf and Californiacoastal areas (including those volumesof onshore-generated drilling wastesand those offshore-generated drillingwastes which are currently brought to-shore for land disposal). The 1.6 millionbarrels per year of drilling wastes thatwould be disposed onshore undertoday's preferred option representsapproximately 3.5 percent of theestimated available land disposalcapacity in these coastal areas, whichthe Agency believes to be a reasonableuse of the available capacity.

3. Underground Injection of ProducedWater

In the Report to Congress, EPAanalyzed the impact of the disposal ofproduced water in injection wells. Thestudy found that injection wells used forthe disposal of produced water have thepotential to degrade fresh groundwaterin the vicinity if they are inadequatelydesigned, constructed, or operated.Highly mobile chloride ions can migrateinto freshwater aquifers throughcorrosion holes in injection tubing,

casing, and cement. The federalUnderground Injection Control (UIC]program (administered by EPA andstates pursuant to the Safe DrinkingWater Act, sections 1421-1425) requriesmechnical integrity testing of all Class Iinjection wells every 5 years. All statesmeet this requirement, although somestates have requirements for morefrequent testing.

Many states have primacy for the UICprogram. Both the criteria used forpassing or failing an integrity test for aClass 11 well and the testing procedureitself can vary. There is considerablevariation in the actual construction ofClass II wells in operation nationwide,both because many wells in operationtoday were constructed prior to theenactment of current programs andbecause current state programs varysignificantly. State requirements for newinjection wells can be quite extensive.However, state requirements forconstruction of injection wells prior tothe enactment of the UIC program haveevolved over time, and constructionranges from injection wells in which allgroundwater zones are fully protectedwith casing and cementing to shallowInjection wells with one casing stringand little or no cement. Furthermore, theoffshore areas which may be consideredfor reinjection at distances greater than4 miles may not have freshwateraquifers in proximity to the injectionformations.

B. Other FactorsThe industry has argued that injuries

and fatalities due to hauling additionalvolumes of drilling wastes to shorewould increase. Based upon availableinformation, it is likely that the numberof accidents would increase if thevolume of waste transported to shoreincreased. However, it is difficult todetermine quantitatively the increase inaccidents and fatalities.XIX. Solicitation of Comments

The Agency invites and encouragescomments on any aspect of theseproposed regulations. The precedingparts of today's notice list specific areaswhere comments are solicited. Many ofthese areas and several additional areasopen for comment are summarizedbelow. In order for the Agency toevaluate views expressed bycommenters, the comments shouldcontain specific data, references, andinformation to support their views.

A. Industry ProfileThe Agency believes that the

estimated total capital costs andoperation and maintenance costs forBAT produced water are valid even

though the profiling effort does notinclude those structures currentlyproducing in state offshore waters.IPeak and annual average waterproduction rates are calculated for eachmodel project, based on initialproduction rates, initial water cutannual decline rates and the estimatedeconomic lifetime of the model project.For each model project, peak waterproduction rates were used in thedevelopment of capital costs, whileaverage annual water productionvolumes were used to calculateoperating and maintenance costs. TheMinerals Management Service (MMS)reported the water production volumesfor offshore federal waters in the year1987 and state waters records reportedwater production volumes for stateoffshore waters for the year 1986. TheAgency's estimate of average waterproduction volumes in offshore federalwater areas only exceeded thesummation of the MMS and staterecords volumes reported by 60 percent.Since the Agency's water productionvolume did not exceed actual volumes,the capital costs and the operating andmaintenance costs that were developedaccounted for those structures in statewaters that the Agency was unable toprofile. However, because these costsare distributed over fewer structures,the impacts may be somewhat over-estimated.

EPA welcomes comment, informationand data concerning the number ofstructures currently in production instate offshore waters and theirassociated water production using theAgency's definition of "offshore."

B. Produced Water Treatment Costs

The Agency believes that today'sproposal is based on produced watertreatment costs that are substantiallyimproved from those used in the 1985proposal. The capital costs that wereused for the 1985 proposal and havebeen used for today's proposal werecosts supplied to the Agency byindustry. These costs were contained inan October 1975 report entitled,"Potential Impact of EPA Guidelines forProduced Water Discharges from theOffshore and Coastal Oil and GasExtraction Industry." This report wasprepared by Brown and Root for theSheen Technical Subcommittee of theOffshore Operators Committee. In thisreport, costs of equipment were plotted

I Drilling and production efforts In state watersare included in the evaluation of NSPS costs andimpacts for drilling fluids, drill cuttings andproduced water.

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in graphs such as the example shown inFigure 1.

1 0 $ to 30 so Soo

0070 KMGCAAI"(m

In 1982, a second report was preparedfor EPA by Hydrotechnic Corporationentitled. "Cost Estimates for Systems toTreat Produced Water Discharges in theOffshore Gas and Oil Industry to MeetBAT and NSPS." The costs in this reportwere derived from the 1975 Brown andRoot report as follows: for a given pieceof equipment at a given capacity, thecosts were read off of the chartscontained in the report. The costs fromthe charts were adjusted to 1981 costsby applying an inflation factor to them.

Up until late October, 1989, the costsbeing used were the escalated 1981costs from the Hydrotechnic reportwhich were escalated once again toachieve 1986 costs. Comments fromenvironmental groups such as theNatural Resources Defense Councilindicated that the costs used by theAgency in the 1985 Federal Registerwere too high thereby making some ofthe more stringent options economicallyinfeasible. However, no adjustments incosts were made in response to suchcomments.

Since late October 1989, the submitteddata have been extensively correctedthroughout the offshore oil and gasproject The equipment costs used in the1985 proposal were high to begin withand have continually been inflated overthe years. Some re-costing of equipmenthas been performed that has resulted inreduced capital costs and loweredoperating and maintenance costs. Anexample of equipment re-costing is thepump and its associated piping for thedisposal system. For a disposal systemthat has the capacity to handle 200barrels of water per day. The followingcosts from the 1975 Brown and RootReport were used:

Pump .................................................. $946,000Associated Piping ............................ 1,960,000

Total ................ $2,906,000

EPA consulted the Department ofEnergy, Energy InformationAdministration for updated equipmentcosts. The Energy InformationAdministration produces an annualreport, entitled "Costs and Indices forDomestic Oil and Gas Field Equipmentand Production Operations," which is aresult of extensive information gatheringfrom equipment manufacturers andsuppliers. The same 200 barrels of waterper day disposal system costed to be$2.9 million from the 1975 Brown andRoot report was re-costed using theEnergy Information Administrationbasis to be:

Pump and Associated Piping: $240,000.This annual report updates costs on

pumps and disposal systems fordifferent produced water handlingcapacities. This re-costing effort resultedin reductions of up to 91 percent in thecapital costs of these disposal systems.

Once the equipment was re-costedand the engineering errors werecorrected, there was a dramaticreduction in the total capital costs of theproduced water options. For example,the option of a zero dischargerequirement for all structures hadcapital costs reduced by 61 percent andthe operating and maintenance costswere reduced by 54 percent.

The Agency is interested in commenton the cost corrections explained aboveand also the costs associated withinstalling and operating membranefiltration systems. In particular, EPArequests information and data as to thevarious advantages and disadvantagesof membrane systems relative togranular (or other) filtration systems andother produced water treatmentmethods, especially BPT. For example,do membrane or other systems haveadvantages in terms of platform spacerequirements, fitting into theconfiguration of other production andtreatment components, maintenancerequirements, or energy use.

C. Drilling Fluids and Drill CuttingsTreatment Costs

1. Discharge Volumes

For the 1988 Notice of DataAvailability, the Agency used dischargevolumes for drilling fluids and drillcuttings that were submitted in responseto the 1985 proposal. These dischargevolumes were contained in a February,1986 report entitled "Water-basedDrilling Fluids and Cuttings DisposalOption Survey," by Walk, Haydel and

Associates. During the comment periodon the 1988 notice, an updated report fordischarge volumes entitled, "Water-based Drilling Fluids and CuttingsDisposal Study Update," (Walk, Haydeland Associates, November, 1988) wassubmitted to the Agency.

This study update contained resultsfrom the measurement of the dischargevolumes of drilling fluids and cuttingsfrom 15 wells in Mobile Bay. Acomparison of the data from the updatedstudy was made in relation to the datacontained in the 1986 report.

The 1986 report contained dischargevolumes of 1,430 barrels of cuttings and5,349 barrels of drilling fluid (with anadditional 1,400 barrels of fluidallocated to the active mud system) for a10,000 foot well located in the Gulf ofMexico. These data were based ontheoretical calculations used by mostoperators in estimating the volumes ofdrilling wastes reported in the Agency'sDischarge Monitoring Reports.

After review of the 1988 study, theAgency believes for the reasonsexplained below that the data from the1986 Walk, Haydel and Associatesreport provide better information forestimating typical discharge volumes ofdrilling fluids and cuttings from thosereported in the 1988 study for U.S.offshore wells.

2. Well Depths and FormationCharacteristics

For the purpose of costing options fordrilling fluids and cuttings, the averagewell depth in the Gulf of Mexico wasassumed by EPA to be 10,000 feet. In theupdated study, all of the well depthswere over 12,000 feet and over half ofthe wells went to depths of 20,000 feet.These 20,000-foot wells in the MobileBay area were most likely tapping theNorphlet formation which is a hightemperature, high pressure and highsulphur environment. Chevron, USA,Inc. made a request of the MineralsManagement Service to allow a delay infield delineation while developing ametallurgy technology compatible withthe environment. Mobile OilCorporation had to replace liners inNorphlet wells because of corrosion.The Norphlet formation has proven tobe a difficult formation to produce fromand therefore may be an equallydifficult formation to drill. These wellsare atypical of the majority of wellsdrilled and, therefore, the data fromsuch wells do not realistically reflect thepopulation of wells drilled in othersformations.

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3. Calculation of Discharge VolumeRatios

In the 1986 Walk Haydel report, thecalculated discharge volume of drillingfluids and cuttings from an 18,000 footwell was 13,267 barrels. The actualvolume from a 16,300 foot well (whichindustry considers to be similar to an18,000 foot well) was measured to be37,200 barrels. Industry then determinedthe ratio of the actual barrels dischargedto the calculated barrels discharged tobe 37,200/13,267=2.804. The "actual"volume of a 10,000 foot well was thendetermined by multiplying thecalculated volume (1986) of 6,770 barrelsby 2.804:

6,779 X 2.804 = 19,008 barrels

This type of calculation assumes adirect linear correlation between welldepth and discharge volumes of drillingfluids and cuttings. In 1985, theAmerican Petroleum Institute surveyed 1percent of the wells drilled onshore thatyear. It should be noted that the amountof drilling wastes from a given well aremore likely to vary according to thedepth of the well and the formationbeing drilled than whether the well isonshore or offshore. A regressionanalysis was run to fit the data obtainedand the regression eqaations were usedto extrapolate from the samplepopulation to all onshore wells drilled in1985. The 1986 report fit four regressionmodels to the data, however, the modelwith the best fit was:

volume of waste=a(footage)+b(footage 2)-+c

This non-linear relationship can beattributed to several factors: Drillingrate; mud system change overs (eachtime a mud type is changed, the entiremud circulation system is changed aswell); and mud type (larger quantities ofmud are generated if low-density mudsare diluted with water to maintain thesolids concentration below a specifiedlimit).

4. Valuation of Receiving Waters

As Introduced in section XVI.C anddiscussed in section XVII of today'snotice, the Agency is requestingcomment on its approach to valuingmarine waters. The monetized benefitvalues in the RIA primarily focus onhuman health effects. The RIA does notinclude monetized estimates of benefitparameters such as recreational uses orthe intrinsic value of the resource. TheAgency requests comment on the dataand methodologies used in developingthe benefit estimates presented in theRegulatory Impact Analysis.

D. Miscellaneous Discharges

EPA solicits additional informationregarding the pollutant characteristics,sources, and treatment of deck drainage,produced sand, and well treatment,completion, and workover fluids. WhileEPA believes that its proposedtreatment/control options for thesesources are appropriate, the options arebased on limited information.Additional data on pollutant loadingqand quantity is solicited, as well asoperational information on welltreatment, workover and completionfluids including types of fluids, methodsof injection and recovery, operationalpractices.

E. Industry Profile Within Three Miles

As discussed in section V.B, EPAevaluated regulatory options accordingto, among other criteria, distance fromshore. The distances examined include4, 6, and 8 miles from shore. EPA is alsoconsidering regulatory options based on3 miles from shore. However, industryprofile information is limited inside of 3miles. EPA solicits informationregarding numbers and types (i.e., gasonly, oil only, gas and oil), and levels ofproduction and waste discharges of oiland gas extraction producing facilitiesand projections or plans for new welldrillings at 3 miles or less from shore.

F. Membrane Filtration TreatmentTechnology for Produced Waters

As discussed in section X.B, EPA isassessing the performance of membranefiltration on produced waters. EPA willbe collecting sample data on testsperformed at systems operating onoffshore structures following thisproposal. Analysis of these samples willinclude measurements of oil and greaseexclusive of non-hydrocarbon organicmaterials. The Agency has recentlyreceived a petition from the OOCrequesting review and revision of the oiland grease limitations for producedwater based on the current analyticalprocedure not being appropriate. EPArequests additional comment or data onthis subject. EPA is also soliciting anyadditional information on theperformance of membrane filtrationapplications at any locations in the oiland gas industry and its applicability totreating oily waters.

G. Static Sheen Analytical Method

As discussed in section VII, theAgency is not changing the 1985proposal which proposed the StaticSheen Test for determination of thepresence of free oil. The method for thisanalysis was also proposed in thatFederal Register notice. As further

stated in section VII, there have beenother analytical methods developed,that are in use, for the Static Sheen Test.In particular, the analyses developed byRegion IX, and X, and another known Asthe "minimal volume method" arpcurrently in use. These methods varyaccording to the volume of sample, thetype of receiving medium (tap water, orsea water), mixing time, observationtime, and determination criteria for thepresence of free oil.

The Agency is soliciting comments onthe 1985 proposed method and the othermethods described with respect to theirrelative accuracy in identifying thepresence of free oil.H. Radioactivity of Produced Water

As also discussed in section VII, theAgency has conducted a literature anddata gathering search regarding thepresence and levels of radium in-produced waters. Several studies oneffluent or ambient levels of radium inareas surrounding offshore productionsites are cited in section VII, although itwas concluded that data bases arescattered and, for the most part,preliminary. EPA is soliciting commentand additional data concerningradioactivity of produced water, and itseffect on ambient levels in thesurrounding environment. Dependingupon evaluation of additional data andcomments submitted as a result oftoday's proposal, technologies such asion exchange and types of membrane orother filtration suitable for removal ofradioactivity may be considered as atechnology basis for the treatment ofproduced water at promulgation.

I Alaskan Waters

In section XIL EPA explained why itbelieves a zero discharge of drillingfluids and cuttings, based on barging ofwastes, is not appropriate for offshoredrilling operations in Alaskan waters.However, EPA is aware of anexperimental operation to reinjectdrilling wastes. EPA solicits commentsand information on the feasibility ofrequiring zero discharge based onreinjection, rather than barging ofwastes to land for onshore disposal, forAlaskan waters.

f. Treatment/Control Options forDrilling Wastes

In section XIII, EPA lists anddescribes the BAT and NSPS optionsbeing considered for treatment andcontrol of drilling wastes. EPA solicitscomments on the preferred option (4Mile Zero Discharge; 1/1 BeyondOption) and on the other options aswell. EPA especially invites comment on

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the "5/3 All Structures" and the "1/1 AllStructures" discharge options and on the"Zero Discharge All Structures" option.

K. Cadmium Formation Contribution toDrilling Wastes

In section XIII EPA describes ananalysis of data from an API study oncomposition of drilling wastes. Theanalysis of these data estimates that 11to 13 sites had higher concentrations ofcadmium in their drilling fluids than intheir barite. Certain assumptions arenecessary in order to assign theincreases in cadmium levels in thedrilling fluids to sources other than thebarite or to the formation being drilled.The assumption that cadmium isuniformly distributed throughout thebarite and the drilling fluids must bemade, the other components of thedrilling fluid system do not contribute tothis increase in cadmiumlevels, andthat these sites are representative of thelocations at future drilling will occur.

L Treatment/Control Options forProduced Water

In section XIII EPA describes the BAToptions being considered for treatmentand control of produced waters. Thetypes of control involve variouscombinations of treatment anddischarge and/or zero discharge. Thetreatment and discharge technologiesconsidered in the options describedinvolve either BPT, filtration, orreinjection. Each option also variesaccording to requriements which maydiffer with respect to depth or distancefrom shore. EPA solicits comments onthe viability and appropriateness ofthese options, especially with respect tothe "Filtration All Structures," "BPT AllStructures," and the "Zero Discharge"options. In addition, EPA solicitscomment on the impact of producedwater radioactivity on the viability andappropriateness of the proposedtreatment options. EPA intends to issuea Notice of Data Availability and willtake all available information intoaccount in developing final regulatorycontrols on produced water.

M. Environmental Impact Analysis

Section XVII describes theenvironmental impact/benefit analysesperformed by EPA on the proposedregulatory options for drilling wastesand produced waters. EPA believes thatthe water quality and cost/benefitanalyses performed on both of thesewaste sources underestimates thebenefits derived from the proposedregulations because only eightpollutants are used to represent averageindustry-wide discharges. These eightpo!lutants, according to EPA data, are

those that are consistently present insignificant levels. Some of the pollutantsexcluded from consideration were foundin insignificant quantities or numbers offacilities. Yet, some of these pollutantsare highly toxic. This analysis also doesnot consider impacts of variousproduced water additives, especiallybiocides, due to the lack of specific dataon the use of these components. Thus,EPA solicits additional information onproduced water and drilling wastecharacteristics, especially with respectto toxic pollutants, biocides, and use ofother toxic additives. EPA also solicitsinformation on the environmentalimpacts associated with thesedischarges.

XX. Variances and Modifications

A. Stormwater VarianceA concern not previously addressed is

with respect to noncompliance with thedeck drainage regulations because ofstorms. Rainwater comes in contact withthe decks of the platforms and any opentreatment or storage devices. Short-term,high volume loadings can temporarilyinterfere with treatment and controlprocesses. One way to handle this is torequire a certain size holding tankcapable of containing stormwaterassociated with a certain size stormevent until it can be routed to thetreatment system, and allowing avariance for any overflows that mayoccur. Another method would be toallow a variance during the initialperiod (the "first flush") of the stormevents and for a designated period aftercertain sized storm events.

EPA solicits comment on theappropriate approach to stormexemptions, especially regarding theappropriate size of storm events whichwould trigger a variance allowance, orthe appropriate capacity of stormwaterholding tanks.

EPA also solicits comment on BestManagement Practices (BMPs)applicable to deck drainage. Such BMPscould, for example, require a regularwashdown schedule where the drainageis sent through the major wastewatertreatment system, thereby being subjectto controls on produced water.

XXI. OMB ReviewThis regulation was submitted to the

Office of Management and Budget(OMB) for review as required byExecutive Order 12291. Any writtencomments from OMB to EPA and anyEPA responses to those comments areavailable for public inspection at theEPA Public Information Reference Unitlisted in the ADDRESSES section oftoday's notice.

List of Subjects in 40 CFR Part 435

Oil and gas extraction, Wastetreatment and disposal, Water pollutioncontrol.

Dated. February 28, 1991.F. Henry Habicht,Acting Administrator.

Appendices

Appendix A-Abbreviations, Acronyms, andOther Terms Used In This Notice

Act-Clean Water AcLAgency-U.S. Environmental Protection

Agency.API-American Petroleum Institute.ASTM-American Society for Testing and

Materials.BAT-Best available technology

economically achievable, under section304{b)(2)[B) of the Act.

BCT-Best conventional pollutant controltechnology, under section 304(b)(4) of the Act.

BMP-Best Management practices.BOD-Biochemcal oxygen demand.BPT-Best practicable control technology

currently available, under section 304(b)(1) ofthe Act

Bypass--An act of intentionalnoncompliance during which waste treatmentfacilities are circumvented because of anemergency situation.

Clean Water Act-The Federal WaterPollution Control Act Amendments of 1972(33 U.S.C. 1251 et seq.), as amended by theClean Water Act of 1977 and Water QualityAct of 1987.

LC5O--The concentration of a test materialthat is lethal to 50 percent of the testorganisms in a bioassay.

NPDES Permit-National PollutantDischarge Elimination System permit issuedunder section 402 of the Act.

NRDC-Natural Resources DefenseCouncil.

NSPS-New source performance standardsunder section 306 of the Act.

OCS-Outer Continental Shelf.OOC-Offshore Operators Committee.PESA-Petroleum Equipment Suppliers

Association.Priority Pollutants-The 65 pollutants and

classes of pollutants declared toxic undersection 307(a) of the Act.

RCRA-Resource Conservation andRecovery Act (Pub. L 94-580) of 1976.Amendments to Solid Waste Disposal Act (42U.S.C. 6901 et seq.).

SPP-Suspended particulate phase.Spot-The introduction of oil to a drilling

fluid system for the purpose of freeing a stuckdrill bit or string.

Upset-An unintentional noncomplianceoccurring for reasons beyond the reasonablecontrol of the permittee.

Appendix B-Major Documents Supportingthe Proposed Reglulation

1. ERC Environmental and Energy ServicesCo. for EPA, "An Evaluation of TechnicalExceptions for Brine Reinjection for theOffshore Oil and Gas Industry", January1991.

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2. Offshore Operators Committee, "Gulf ofMexico Spotting Fluid Survey", prepared byExxon Production Research Company andChevron, USA, Inc., April 4,1987.

3. Offshore Operators Committee, "FinalReport for Research Program on OrganicChemical Characterization of Diesel andMineral Oils Used as Drilling MudAdditives-Phase II", prepared by BattelleNew England Marine Research Laboratory,December 24, 1986.

4. EPA/API Diesel Pill Monitoring Program,presented at the 1988 InternationalConference on Drilling Wastes, Calgary,Alberta, Canada, April 5-8,1988.

5. Science Applications InternationalCorporation of EPA, "Summary of DataRelating to Minor Discharges", February 1991.

6. KRE, P.C. for EPA, "Offshore andCoastal Oil and Gas Extraction IndustryStudy of Onshore Disposal Facilities forDrilling Fluids and Drill Cuttings Located inthe Proximity of the Gulf of Mexico". March25, 1987.

7. KRE, P.C. for EPA, "Drilling Fluids andDrill Cuttings Disposal, Offshore Oil and GasExtraction Industry", November 22,1988.

8. ERC Environmental and Energy ServicesCo. for EPA. "Onshore Disposal of OffshoreDrilling Waste--Capacity and Cost ofOnshore Disposal Facilities", February 1991.

9. ERC Environmental and Energy ServicesCo. for EPA, "Review of Static Sheen TestingProcedures", January 1990.

10. American Petroleum Institute, "ANational Survey on Naturally OccurringRadioactive Materials (NORM) in PetroleumProducing and Gas Processing Facilities",July 1989.

11. EPA. "Development Document for 1991Proposed Effluent Limitations Guidelines andNew Source Performance Standards for theOffshore Subcategory of the Oil and GasExtraction Point Source Category". February1991.

12. Walk, Haydel and Associates, "Water-based Drilling Fluids and Cuttings DisposalStudy Update", January 1989.

13. Technical Resources, Inc., "The NPDESDrilling Fluids Toxicity Test VariabilityStudy", February 1991.

14. EPA, "Economic Impact Analysis ofProposed Effluent Limitations Guidelines andStandards of Performance for the OffshoreOil and Gas Industry". February 1991.

15, EPA. "Cost-Effectiveness Analysis ofProposed Effluent Limitations Guidelines andStandards of Performance for the OffshoreOil and Gas Industry", February 1991.

16. EPA, "Regulatory Impact Analysis ofthe Effluent Guidelines Regulation for theOffshore Subcategory of the Oil and GasExtraction Industry", February 19, 1991.Appendix C--Regulatory Boundaries

Structures discharging to the followingareas shall be considered "shallow." Unlessotherwise stated below, the outer boundaryfor each designated area is the 200-mileboundary of the Fishery Conservation Zone.(A) Gulf of Mexico-Water Depth 20 Metersor Less

Extending from the inner boundary of theterritorial seas of Eastern Texas, Louisiana,Mississippi, Alabama, and Eastern Florida.

(B) Atlantic Coast-Water Depth 20 Metersor Less

Extending from the inner boundary of theterritorial seas offshore of the contiguousstates between and including Maine andFlorida.

(C) California Coast-Water Depth 50Meters or Less

Central and Northern California: Extendingoffshore of California and bounded on thenorth by approximately 42* N. latitude andbounded on the south by the U.S.-Mexicoboundary.

(D) Alaska1. Gulf of Alaska-water depth 50 meters

or less: It is bounded approximately on thewest by 131" 55' W. longitude, thence eastalong 58' N. latitude to 147' V. longitude,thence south.

2. Cook Inlet/Shelikof Strait-water depth50 meters or less: Lies east of 156* W.longitude and north of 57" N. latitude to theinner boundary of the territorial seas nearKelgin Island.

3. Bristol Bay/Aleutian Range-waterdepth 50 meters or less: (a) North AleutianBasin: Lies in the eastern Bering Seanorthwest of the Alaskan Peninsula andsouth of 59" N. latitude. It is bounded on thewest by 165" W. longitude and on the east bythe inner boundary of the territorial seas.

(b) St. George Basin-water depth 50meters or less: Lies in the eastern Bearing Seanorthwest of the Aleutian Islands chain andis bounded on the north by 59' N. latitudeand on the west by 174' W. longitude from59* N. latitude to 56* N. latitude, thence eastto 171° W. longitude, thence south. It isbounded on the east by 165' W. longitude.

4. Norton Basin-water depth 20 meters orless: Lies south and southwest of the SewardPeninsula. It is bounded on the south by 63N. latitude, on the west by the U.S.-RussiaConvention Line of 1867, on the north by 65"34' N. latitude, and on the east by the innerboundary of the territorial seas.

5. Beaufort Sea-water depth 10 meters orless: Lies offshore of Alaska in the BeaufortSea and the Arctic Ocean. It is bounded onthe west by the Mineral Management ServiceChukchi Sea planning area, extends eastwardto the limit of U.S. jurisdiction, and on thesouth by the inner boundary of the territorialseas.

To determine water depth at the facilitylocation, reference that most recent nauticalcharts or bathymetric maps with the smallestscale (highest resolution) available from theNational Oceanic and AtmosphericAdministration for the area in question.Water depth is the mean lower low waterdepth indicated on the appropriate map forthe location of the facility or discharge.Water depth at the facility is based upon theproposed location of the facility's well slotstructure or produced water discharge point.

For the reasons set out in thepreamble, title 40, part 435 of the Codeof Federal Regulations is proposed to beamended as set forth below:

PART 435-OIL AND GASEXTRACTION POINT SOURCECATEGORY

1. The authority citation for part 435 isrevised to read as follows:

Authority: Secs, 301, 304, 306, 307, and 501,Public Law 92-500, 86 Stat. 816, Public Law95-217,91 Stat. 156, Public Law 100-4, 101Stat. 7 (33 U.S.C. 1311,1314, 1316,1317, and1361).

2.40 CFR part 435, subpart A isproposed to be revised to read asfollows:Subpart A--Offshore Subcategory

Sec.435.10 Applicability; description of the

offshore subcategory.435.11 Specialized definitions.435.12 Effluent limitations guidelines

representing the degree of effluentreduction attainable by the application ofthe best practicable control technologycurrently available (BPT).

435.13 Effluent limitations guidelinesrepresenting the degree of effluentreduction attainable by the application ofthe best available technologyeconomically achievable (BAT).

435.14 Effluent limitations guidelinesrepresenting the degree of effluentreduction attainable by the application ofthe best conventional pollutant controltechnology (BCT).

435.15 Standards of performance for newsources (NSPS).

Subpart A-Offshore Subcategory

§ 435.10 Applicablity, description of theoffshore subcategory.

The provisions of this subpart areapplicable to those facilities engaged infield exploration, drilling, wellproduction, and well treatment in the oiland gas extraction industry which arelocated in waters that are seaward ofthe inner boundary of the territorial seas("offshore") as defined in section 502(g)of the Clean Water Act. This includesoffshore facilities that transport wastesto onshore locations for treatment ordisposal.

§ 435.11 Specialized definitions.For the purpose of this subpart:(a) Except as provided below, the

general definitions, abbreviations andmethods of analysis set forth in 40 CFRpart 401 shall apply to this subpart.

(b) The term drilling fluid shall referto the circulating fluid (mud) used in therotary drilling of wells to clean andcondition the hole and tocounterbalance formation pressure. Awater-base drilling fluid is theconventional drilling mud in whichwater is the continuous phase and thesuspending medium for solids, whetheror not oil is present. An oil-base drilling

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Federal Regster / Vol. 56, No. 49 / Wednesday, March 13, 1991 / Proposed Rules

fluid has diesel, crude, or some other oilas its continuous phase with water asthe dispersed phase.

(c) The term drill cuttings shall referto the particles generated by drilling intosubsurface geologic formations andcarried to the surface with the drillingfluid.

(d) The term deck drainage shall referto any waste resulting from deckwashings, spillage, rainwater, and runofffrom gutters and drains including drippans and work areas within facilitiessubject to this subpart.

(e) The term produced water shallrefer to the water (brine) brought upfrom the hycarbon-bearing strata duringthe extraction of oil and gas, and caninclude formation water, injectionwater, and any chemicals addeddownhole or during the oil/waterseparation process.

(f) The term produced sand shall referto slurried particles used in hydraulicfracturing, the accumulated formationsands and scales particles generatedduring production. Produced sand alsoincludes desander discharge from theproduced water waste stream andblowdown of the water phase from theproduced water treating system.

(g) The term well treatment fluidsshall refer to any fluid used to restore orimprove productivity by chemically orphysically altering hydrocarbon-bearingstrata after a well has been drilled.

(h) The term sanitary waste shall referto human body waste discharged fromtoilets and urinals located withinfacilities subject to this subpart.

(i) The term domestic waste shallrefer to materials discharged from sinks,showers, laundries, safety showers, eye-wash stations, hand-wash stations, fishcleaning stations, and galleys locatedwithin facilities subject to this subpart.

The term M.9LM shall mean thoseoffshore facilities continuously mannedby nine (9) or fewer persons or onlyintermittently manned by any number ofpersons.

(k) The term M1O shall mean thoseoffshore facilities continuously mannedby ten (10) or more persons.

(1) The term no discharge of free oilshall mean that waste streams may notbe discharged when they would cause afilm or sheen upon or a discoloration ofthe surfact of the receiving water, asdetermined by the Static Sheen Test.

(m) The term Static Sheen Test shallrefer to the standard test procedure thathas been developed for this industrialsubcategory for the purpose ofdemonstrating compliance with therequirement of no discharge of free oil.

(n) The term diesel oil shall refer tothe grade of distillate fuel oil, asspecified in the American Society for

Testing and Materials StandardSpecification D975-81. that is typicallyused as the continuous phase inconventional oil-based drilling fluids.

(o) The term 96-hour LC5O shall meanthe concentration of test material that islethal to 50% of the test organisms in abioassay after 98 hours of constantexposure.

(p) The term exploration facility shallmean any fixed or mobile structuresubject to this subpart that is engaged inthe drilling of wells to determine thenature of potential hydrocarbonreservoirs.

(q) The term development facilityshall mean any fixed or mobile structuresubject to this subpart that is engaged inthe drilling of productive wells.

(r) The term production facility shallmean any platform or fixed structuresubject to this subpart that is eitherengaged in well completion or used foractive recovery of hydrocarbons fromproducing formations.

(s) The term new source means anyexploratory, development or productionfacility or activity that meets thedefinition of "new source" under 40 CFR122.2 and meets the criteria fordetermination of new sources under 40CFR 122.29(b) applied consistent withthe following definitions:

(1) The term water area as used in theterm "site" in 40 CFR 122.29 and 122.2shall mean the water area and oceanfloor beneath any exploratory.development, or production facilitywhere such facility is conducting itsexploratory, development or productionactivities.

(2) The term significant sitepreparation work as used in 40 CFR122.29 shall mean the process ofsurveying, clearing and preparing anrea of the ocean floor for the purpose

of constructing or placing a developmentor production facility on or over the site.

(t) The term gas well shall refer to anywell that produces more than 15,000cubic feet of natural gas for each barrelof produced petroleum liquids.

(u) The term oil development andproduction facilities shall mean thosefacilities subject to this subpart that areengaged in the development of orproduction from oil wells or oil and gaswells.

(v) The term maximum for any oneday as applied to BPT and BCT effluentlimitations for oil and grease inproduced water shall mean themaximum concentration allowed asmeasured by the average of four grabsamples collected over a.24-hour periodthat are analyzed separately.

(w) The term maximum as applied toBAT effluent limitations for drilling

fluids and to NSPS for produced waterand drilling fluids shall mean themaximum concentration allowed asmeasured in any single sample of thedischarged waste stream.

(x) The term minimum as applied toBAT effluent limitations and NSPS fordrilling fluids shall mean the minimum96-hour LC50 value allowed asmeasured in any single sample of thedischarged waste stream.

(y) The term well completion fluidsmeans: Salt solutions, weighted brines,polymers, and various additives used toprevent damage to the well bore duringoperation which prepare the drilled wellfor hydrocarbon production.

(z) The term workoverfluids means:.Salt solutions, weighted brines,polymers, or other specialty additivesused in a producing well to allow saferepair and maintenance orabandonment procedures.

§ 435.12 Effluent limitations guidelinesrepresenting the degree of effluentreduction attainable by the application ofthe best practicable control technologycurrently avalable (P)

Except as provided in 40 CFR 125.30-125.32. any existing point source subjectto this subpart must achieve thefollowing effluent limitationsrepresenting the degree of effluentreduction attainable by the applicationof the best practicable controltechnology currently available:

BPT effluent limitations oil and greasemg/I

Pollutant Average ofparameter values for Residual

waste Maximum 30 chlorinesource for any I consecu- minimum

day tive days for any tshall not dayeoed

Producedwater ........

Deckdrinage..

Drilltflings ....

WellVeatmentflufs._.

M10.i

Domestic..

72

(1)

4')

(,)

(,)

NANANA

NA

NA

NA

NA

NA

aINANA

'No dWlhar of free oil.'Minimum of 1 mg/I and aintained as dose to

this concentration as possioe.'There shell be no floating solids as a result of

the discharge of these wastes.NA- Not applicale

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§ 435.13 Effluent limitations guidelinesrepresenting the degree of effluentreduction attainable by the application ofthe best available technology economicallyachievable (BAT).

Except as provided in 40 CFR 125.30-125.32, any existing point source subjectto this subpart must achieve thefollowing effluent limitationsrepresenting the degree of effluentreduction attainable by the applicationof the best available technologyeconomically achievable (BAT):

BAT effluent limitationsWaste source Pollutant BAT effluent

parameter limitation

Producedwater.

(A) Forfacilitieslocated 4milesoffshoreor less.

(B) Forfacilitieslocatedmorethan 4milesoffshore.

Oil and grease....

Oil and grease....

The maximumfor any oneday shall notexceed 13mg/I; theaverage ofdaily valuesfor 30consecutivedays shallnot exceed 7mg/L

The maximumfor any oneday shall notexceed 72mg/I; theaverage ofdaily valuesfor 30consecutivedays shallnot exceed48 mg/I.

BAT effluent limitations

Waste source Pollutant BAT effluent

parameter limitation

Drilling fluidsand cuttings:


(B) Forfacilitieslocatedmorethan 4milesoffshore.

Well treatment,completionand workoverfluids.

Deck drainageduringproduction:


.. . INo discharge.'

Toxicity ...............

Free oil ...............Diesel oil .............

M ercury ...............

Cadm ium .............

Oil and grease....

Minimum 96-hour LC5O ofthe SPP shallbe 3% byvolume.

No discharge.'No discharge In

detectableamounts.

1 mg/kg dryweightmaximum Inthe wholedrilling fluid.

1 mg/kg dryweightmaximum inthe wholedrilling fluid.

Zero dischargeof fluids slugplus 100-barrel bufferon eitherside.

The maximumfor any oneday shall notexceed 13mg/I; theaverage ofdaily valuesfor 30consecutivedays shallnot exceed 7mg/L

BAT effluent limitations

Waste source Pollutant BAT effluentparameter limitation

(B) For Oil and grease.... The maximumfacilities for any onelocated day shall notmore exceed 72than 4 mg/I; themiles average ofoffshore. daily values

for 30consecutivedays shallnot exceed48 mg/I.

Deck drainage Free oil ............... No discharge.'during drilling.

Produced sand .................. Zero discharge.Sanitary MIO ........ None ...................Sanitary M91M .... None ...................Domestic waste.. None ....................

I All Alaskan facilities are subject to the drillingfluids and cuttings discharge limitations for facilitieslocated more than 4 miles offshore.

' Based on Static Sheen Test.

§ 435.14 Effluent limitations guidelinesrepresenting the degree of effluentreduction attainable by the application ofthe best conventional pollutant controltechnology (BCT).

Except as provided in 40 CFR 125.30-125.32, any existing point source subject

to this subpart must achieve thefollowing effluent limitationsrepresenting the degree of effluentreduction attainable by the applicationof the best conventional pollutantcontrol technology (BCT):

BCT effluent flmltationsWaste source

Pollutant parameter BCT effluent limitation

Produced water (all structures) .......................................... Oil & grease ......................................................................... The maximum for any one day shall not exceed 72mg/l; the average of daily values for 30 consecu-tive days shall not exceed 48 mg/L

Drilling fluids and cutfings:(A) For facilities located 4 miles offshore or less .................................................................................................... No discharge '.(B) For facilities located more than 4 miles off- Free oil .................................................................................. No discharge t.

shore.Well treatment, completion and workover fluids .............. Free oil ................. . . . ... No discharge'.Deck drainage ..................................................................... Free oil ................................................................................ No discharge'.Produced sand .................................................................. Free oil ............................................................................... No discharge '.Sanitary M10 ....................................................................... Residual chlorine ............................................................... Minimum of 1 mg/I and maintained as close to this

a possible.Sanitary MgIM ...................................................................... Floating solids ................................................................... No dishcarge.Domestic waste .................................................................... Floating solids .................................................................... No discharge.

I All Alaskan facilities are subject to the drilling fluids and drill cuttings discharge limitations for facilities located more than 4 miles offshore.*Based on the Static Sheen Test.

§ 435.15 Standards of performance fornew sources (NSPS).

Any new source subject to thissubpart must achieve the following newsource performance standards (NSPS):

10714



NSPS effluent limitationsWaste source

IPollutant parameter NSPS effluent limitation

Produced water(A) For facilities located 4 miles offshore or less...

(8) For facilities located more than 4 miles off-shore.

Drilling fluids and cuttings:(A) For facilities located 4 miles offshore or less...(B) For facilities located more than 4 miles off-

shore.

Well treatment, completion and workover fluids .............

Deck drainage during production:(A) For facilities located 4 miles offshore or less...

(B) For facilities located more than 4 miles off-shore.

Deck drainage during drilling .............................................Produced sand ....................................................................Sanitary M10 .......................................................................

Dom estic W aste ..................................................................

LAI a ur~tnou ....................................... .................................

Oil & grease .........................................................................

TO)dc. .................................................................................

Free oil .................................................................................

Mercury..

U p rp........................................au,~I,.

Oil & gre

Oil & gre

Free oil.

W...................... .................

sz ..... a...................... ...........

Residual chlorina ................................................................

e.. . ............................................... .................................. NO Oiscnarge.

The maximum for any one day shall not exceed 13mg/I; the average of daily values for 30 consecu-tive days shall not exceed 7 mg/1.

The maximum for any one day shall not exceed 72mg/I; the average of daily values for 30 consecu-tive days shall not exceed 48 mg/I.

No discharge 1.Minimum 96-hour LC50 of the SPP shall be 3% by

volume.No discharge .No discharge In detectable amounts.1 mg/kg dry weight maximum In the whole drilling

fluid.1 mg/kg dry weight maximum in the whole drilling

fluidZero discharge of fluids slug plus 100-barrel buffer on

either side

The maximum for any one day shall not exceed 13mg/I; the average of daily values for 30 consecu-live days shall not exceed 7 mg/I.

The maximum for any one day shall not exceed 72mg/I; the average of daily values for 30 consecu-tive days shall not exceed 48 mg/1.

No discharge 8.Zero dischargeMinimum of 1 mg/I and maintained as close to this

as possible.No discharge.No discharge.

4. _______________________ 4. _______________________

I All Alaskan facilities are subject to the drilling fluids and cuttings discharge limitations for facilities located more than 4 miles offshore.' Based on Static Sheen Test.

[FR Doc. 91-5553 Filed 3-12-91; 8:45 am]

BILUNG CODE 6560--M

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Federal Register Vol. No. 49 Wednesday, March 13, 1991 ...€¦ · 3/13/1991 · Federal Register...

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Transcript of Federal Register Vol. No. 49 Wednesday, March 13, 1991 ...€¦ · 3/13/1991 · Federal Register...