federal register vol. 50, no. 165 monday, august 26, 1985

Federal Register / Vol. 50, No. 165 / Monday, August 26, 1985 / Proposed Rules

ENVIRONMENTAL PROTECTIONENVIRONMENTAL PROTECTIONAGENCY

40 CFR Part 435

[FRL-2719-1]

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

AGENCY: Environmental ProtectionAgency (EPA).ACTION: Proposed regulation and requestfor comments.

SUMMARY: 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), bestavailable technology economicallyachievable (BAT) and best conventionalpollutant control technology (BCT)effluent limitations guidelines for theoffshore segment of this industry. Afterconsidering comments received inresponse to this proposal, EPA willpromulgate a final rule. This proposalwould also amend the current definitionof "free oil" and the analytical methodof compliance, both of which will applyto BPT as well as BAT, BCT and NSPS.

The Agency has scheduled twotechnical workshops for State and EPApermit writers. EPA will present andexplain the proposed regulation at theseworkshops. The Agency believes theworkshop information will also be ofinterest to industry representatives andmembers of environmental and publicinterest groups.DATES: The comment period for thisproposed rule will begin on September16, 1985 and end on December 16, 1985.The development documents andrulemaking record for this proposed rulewill be available beginning September16, 1985.

The general public is invited to attendthe workshops on September 24-25 inNew Orleans, Louisiana, and October29-30 in Santa Barbara, California. Forlocations and time please see theADDRESSES section of this document.ADDRESSES: Comments should be sentto Mr. Dennis Ruddy, IndustrialTechnology Division (WH-522],Environmental Protection Agency, 401 MStreet, S.W., Washington, D.C. 20460.

The supporting information and allcomments on this proposal will beavailable for inspection and copying atthe EPA Public Information ReferenceUnit, Room 2402 (Rear of EPA Library).The EPA public information regulation

(40 CFR Part 2] provides that areasonable fee may be charged forcopying. Technical information andcopies of technical documents may beobtained from Mr. Dennis Ruddy at theabove address. The economic analysisreport may be obtained from Ms.Kathleen Ehrensberger, EconomicAnalysis Staff (WH-586), EnvironmentalProtection Agency, 401 M Street, S.W.,Washington, D.C. 20460, or call (202)382-5397. The environmentalassessment report may be obtained fromMs. Eleanor Zimmerman, IndustrialTechnology Division (WH-552), at theabove address, or call (202) 382-7126.

The workshops will be conducted atthe following locations:September 24-25, 1985, Sheraton New

Orleans Hotel, 500 Canal Street, NewOrleans, Louisiana

October 29-30, 1985, Sheraton SantaBarbara Hotel, 1111 East CabrilloBoulevard, Santa Barbara, CaliforniaThere will be no pre-registration. On-

site registration will begin at 8:30 a.m.The workshops will be conducted from9:00 a.m. to 4:00 p.m. local time.FOR FURTHER INFORMATION CONTACT:Mr. Dennis Ruddy at the above address,or call (202) 382-7131.SUPPLEMENTARY INFORMATION:

Organization of This NoticeIntroduction1. Legal AuthorityII. Scope of This RuletnakingII1. Summary of Legal BackgroundIV. Prior EPA RegulationsV. Overview of the Industry

A. Industry ProfileB. Exploration, Development, and

ProductionC. Waste Streams

VI. Summary of MethodologyVII. Data Gathering Efforts

A. Existing InformationB. Additional Data CollectionC. Sampling and Analytical ProgramsD. Environmental Effects Information

CollectionE. Economic Information Collection

VIII. Waste CharacterizationA. Produced WaterB. Drilling FluidsC. Drill CuttingsD. Deck DrainageE. Sanitary WastesF. Domestic WastesG. Produced SandH. Well Treatment Fluids

IX. Industry SubcategorizationX. Control and Treatment Technologies

A. Current PracticeB. Additional Technologies Considered

XI. Selection of Control and TreatmentOptions

A. New Source Performance StandardsB. Best Available TechnologyC. Best Conventional TechnologyD. Best Practicable Technology

XII. Cost and Economic Impact

A. Treatment Technology CostsB. Compliance Monitoring CostsC. Economic Impact

XIII. Non-Water Quality Aspects of PollutionControl

A. EnergyB. Air pollutionC. Solid WasteD. Consumptive Water Loss

XIV. New Source DefinitionXV. Best Management PracticesXVI. Upset and Bypass ProvisionsXVII. Variances and ModificationsXVIII. Relationship to NPDES PermitsXIX. Summary of Public ParticipationXX. Alternative Approaches to Regulation

A. Diesel Oil RecoveryB. Specific Pollutant ApproachC. Alternatives for Regulating Produced

Water DischargesD. Oil Control Limitations

XXI. Solicitation of CommentsXXII. Executive Order 12291XXIII. Regulatory Flexibility AnalysisXXIV. OMB ReviewXXV. List of Subjects in 40 CFR Part 435XXVI. Appendices

A. Abbreviations, Acronyms, and OtherTerms Used in This Notice

B. Generic Drilling Fluids ListC. 126 Priority PollutantsD. Major Documents Supporting the

Proposed Regulation

Introduction

The Supplementary Informationsection of this preamble describes thelegal authority and background, thetechnical and economic bases, and otheraspects of the proposed regulations.That section also solicits comments onspecific areas of interest. Abbreviations,and other terms used in this preamble,generic drilling fluids, prioritypollutants, and certain technical,economic and environmental documentsused in regulation development arelisted in Appendices A through D to thispreamble.

These proposed regulations aresupported by documents available fromEPA. Technical conclusions are detailedin the Development Document forProposed Effluent LimitationsGuidelines and New SourcePerformance Standards for the OffshoreSegment of the Oil and Gas ExtractionPoint Source Category (EPA 440/1-85/0556). The Agency's economic analysisis found in Economic Impact Analysis ofProposed Effluent Limitations andStandards for the Offshore Oil and GasIndustry (EPA 440/2-85/003). Anenvironmental analysis is presented inAssessment of Environmental Fate andEffects of Discharges from Offshore Oiland Gas Operations (EPA 440/4-85/002).

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I. Legal Authority

The regulations described in thisnotice are proposed under the authorityof Sections 301, 304, 306, 307, and 501 ofthe Clean Water Act (the Federal WaterPollution Control Act Amendments of1972, 33 U.S.C. 1251 et seq., as amendedby the Clean Water Act of 1977, Pub. L.95-217), also called the "Act." Theseregulations are also proposed inresponse to the Court Order in NaturalResources Defense Council, Inc. v.Castle, C.A. No. 79-3442 (D.D.C.) July 7,1980.

II. Scope of This RulemakingThe purpose of this rulemaking is to

propose standards of performance fornew sources and effluent limitationsguidelines for existing sources undersections 301, 304, 306, 307 and 501 of theClean Water Act.

These proposed regulations wouldapply to discharges from offshore oiland gas extraction facilities, includingexploration, development andproduction operations. These processesand operations comprise the offshore oiland gas extraction segment (StandardIndustrial Classification (SIC) MajorCroup 13).

EPA's 1973 to 1976 rulemaking effortsemphasized the achievement of bestpracticable control technology currentlyavailable (BPT) by July 1, 1977. Ingeneral, BPT represents the average ofthe best existing performances of wellknown technologies for control oftraditional (i.e., "classic") pollutants.BPT for this industrial subcategorylimits the discharge of oil and grease inproduced water to a daily maximum of72 mg/l and a thirty day average of 48mg/l; prohibits the discharge of free oilin deck drainage, drilling fluids, drillcuttings, and well treatment-fluids;requires a minimum residual chlorinecontent of 1 mg/l in sanitary discharges;and prohibits the discharge of floatingsolids in sanitary and domestic wastes.

This rulemaking aims for theachievement of the best availabletechnology economically achievable(BAT) that will result in reasonablefurther progress toward the nationalgoal of eliminating the discharge of allpollutants. At a minimum, BATrepresents the best economicallyachievable performance in the industrialcategory or subcategory. Moreover, as aresult of the Clean Water Act of 1977,the emphasis of EPA's program hasshifted from "classical" pollutants to thecontrol of listed toxic pollutants. TheBAT effluent limitations guidelinesbeing proposed today would prohibit thedischarge of free oil in drilling fluids,deck drainage, drill cuttings, produced

sand and well treatment fluids; prohibitthe discharge of drilling fluids that areoil-based or that contain diesel oil;prohibit the discharge of drill cuttingsthat are contaminated with diesel oil orthat are generated with the use ofdrilling fluids that are oil-based; limitthe acute toxicity of drilling fluiddischarges to a minimum 96-hr LC-50(lethal concentration to 50 percent of thetest organisms of 3 percent (30,000 ppm)as measured in the diluted suspendedparticulate phase (SPP); and limit thedischarge of cadmium and mercury indrilling fluids to a maximum of 1 mg/kg,each (whole fluid basis). BAT effluentlimitations guidelines for producedwater, and for deck drainage, producedsand and well treatment fluids forpollutants other than free oil are beingreserved for future rulemaking.

EPA is proposing BCT equal to thepreviously promulgated BPT effluentlimitations guidelines. EPA is, however,reserving BCT effluent limitationsguidelines for additional conventionalpollutant parameters in deck drainage,drilling fluids, drill cuttings, producedsand, and well treatment fluids forfuture rulemaking.

New source performance standardsare also being proposed today. Theseproposed standards are the same as theAgency's proposed BAT/BCT effluentlimitations guidelines with oneexception. EPA is proposing aprohibition on the discharge of producedwater from all offshore oil productionfacilities that are located in or woulddischarge to shallow water areas asdefined in the proposed regulation.Produced water discharges from allother new source offshore facilitiesengaged in exploration, development,and production activities would belimited to a maximum oil and greaseconcentration of 59 mg/l (i.e., no singlesample to exceed).

III. Summary of Legal BackgroundThe Federal Water Pollution Control

Act Amendments of 1972 established acomprehensive program to "restore andmaintain the chemical, physical, andbiological integrity of the Nation'swaters," Section 101(a). To implementthe Act, EPA is to issue effluentlimitations guidelines, new sourceperformance standards, andpretreatment standards for industrydischargers. These are discussed indetail in the Development Documentsupporting these proposed regulations.The following is a brief summary:

1. Best Practicable ControlTechnology Currently Available (BPT).BPT limitations are generally based onthe average of the best existingperformance by plants of various sizes,

ages, and unit processes within theindustry or subcategory.

In establishing BPT limitations, EPAconsiders the total cost of applying thetechnology in relation to the effluentreduction derived, the age of equipmentand facilities involved, the processemployed, the engineering aspects ofcontrol technologies, process changes,and nonwater quality environmentalimpacts (including energy requirements)and other factors the Administratorconsiders appropriate. The total cost ofapplying the technology is balancedagainst the effluent reduction. EPApromulgated BPT for the offshoresegment of the oil and gas extractionpoint source category on April 13, 1979(44 FR 22069). The only portion of theBPT regulation being opened forcomment today is the proposed changein definition of "no discharge of free oil"and the method for determiningcompliance with this limitation.Otherwise, BPT is printed in thisproposed rule only for sake ofcompleteness to the reader.

2. Best Available TechnologyEconomically Achievable (BAT). BATlimitations, in general, represent the bestexisting performance of technology inthe industrial category of subcategory.The Act establishes BAT as theprincipal national means of controllingthe direct discharge of toxic andnonconventional pollutants to navigablewaters.

The factors considered in assessingbest available technology economicallyachievable (BAT) include the age ofequipment and facilities involved, theprocess employed, process changes,nonwater quality environmental impacts(including energy requirements) and thecosts of applying such technology(section 304(b)(2)(B) of the Clean WaterAct). At a minimum, the BAT technologylevel represents the best economicallyachievable performance of plants ofvarious ages, sizes, processes or othershared characteristics. As with BPT,where the Agency has found the existingperformance to be uniformly inadequate,BAT may be transferred from a differentsubcategory or category. BAT mayinclude feasible process changes orinternal controls, even when not incommon industry practice.

The required assessment of BAT"considers" costs, but does not require abalancing of costs against pollutantremoval benefits (see Weyerhaeuser v.Castle, supra). In developing theproposed BAT, however, EPA has givensubstantial weight to the reasonablenessof cost. The Agency has considered thevolume and nature of dischargesexpected after application of BAT, the

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general environmental effects of thepollutants, and the costs and economicimpacts of the required pollution controllevels.

Despite this expanded considerationof costs, the primary determinant ofBAT is still pollutant removal capability.As a result of the Clean Water Act of1977, the achievement of BAT hasbecome the principal national means ofcontrolling toxic water pollution.

3. Best Conventional Pollutant ControlTechnology (BCT). The 1977Amendmentadded Section 301(b)(2](E) to the Actestablishing "best conventionalpollutant control technology" (BCT) fordischarge of conventional pollutantsfrom existing industrial point sources.Conventional pollutants are thosedefined in Section 304(a)(4) [biochemicaloxygen demand (BOD5), total suspendedsolids (TSS), fecal coliform and pHl, andany additional pollutants defined by theAdministrator as "conventional" (oiland grease, 44 FR 44501, July 30, 1979].

BCT is not an additional limitation butreplaces BAT for the control ofconventional pollutants. In addition toother factors specified in section304(b)(4)(B), the Act requires the BCTlimitations be assessed in light of a twopart "cost-reasonableness" test,American Paper Institute v. EPA, 660F.2d 954 (4th Cir. 1981). The first testcompares the cost for private industry toreduce its conventional pollutants withthe costs to publicly owned treatmentworks for similar levels of reduction intheir discharge of these pollutants. Thesecond test examines the cost-effectiveness of additional industrialtreatment beyond BPT. EPA must findthat limitations are "reasonable" underboth tests before establishing them asBCT. In no case may BCT be lessstringent than BPT.

EPA published its methodology forcarrying out the BCT analysis on August29, 1979 (44 FR 50372). In the casementioned above, the Court of Appealsordered EPA to correct data errorsunderlying EPA's calculation of the firsttest, and to apply the second cost test.(EPA had argued that the second costtest was not required.]

On October 29, 1982, the Agencyproposed a revised BCT methodology.On September 20, 1984, EPA noticed theavailability of new data and analysesthat it was considering for thedevelopment of BCT limitations (49 FR37046]. EPA is today proposing BCTlimitations for produced water, deckdrainage, drilling fluids, drill cuttings,well treatment fluids, sanitary, domesticand produced sand waste streams. TheAgency is reserving BCT coverage of allpollutants except free oil for deckdrainage, drilling fluids, drill cuttings,

well treatment fluids, and producedsand waste streams pending additionaldata collection and promulgation of thefinal methodology for BCT.

4. Pretreatment Standards. Nopretreatment standards have beenpromulgated for the offshore segment ofthis industry and EPA does not intend topropose pretreatment standards for theoffshore segment. This is because theAgency is not aware of any existing orplanned indirect dischargers in theoffshore segment.

5. New Source Performance Standards(NSPS). The basis for NSPS underSection 306 of the Act is the bestavailable demonstrated technology.New facilities have the opportunity todesign the best and most efficientwastewater treatment technologies.Therefore, Congress directed EPA toconsider the best demonstrated processchanges and end-of-pipe treatmenttechnologies that reduce pollution to themaximum extent feasible.

IV. Prior EPA Regulations

On September 15, 1975, EPApromulgated effluent limitatiorsguidelines for interim final BPT (40 FR42543) and proposed regulations for BATand NSPS (40 FR 42572) for the offshoresegment of the oil and gas extractionpoint source category. The Agencypromulgated final BPT regulations forthe offshore segment on April 13, 1979(44 FR 22069], but deferred action on theBAT and NSPS regulations.

The Natural Resources DefenseCouncil filed suit on December 29, 1979seeking an order to compel theAdministrator to promulgate final NSPSfor the offshore subcategory. Insettlement of NRDC v. Castle, C.A. No.79-3442 (D.D.C.), 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 andreproposal were necessary.Consequently, the Agency withdrew theproposed NSPS on August 22, 1980 (45FR 56115]. The proposed BATregulations were withdrawn on March19, 1981 (46 FR 17567).

This notice serves to propose NSPS,BAT, BCT, and certain amendents toBPT. For convenience to the reader,today's proposed regulation alsocontains all of the existing BPTlimitations applicable to the offshore oiland gas extraction subcategory. Withthe exception of one proposedamendment to BPT, the existing BPTlimitations are not being subjected tocomment. The one proposed amendment

concerns the prohibition on dischargesof free oil, which is discussed below.

Ocean discharge criteria alsoapplicable to this industry segment 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 NPDES permits. Section 403 isintended to prevent unreasonabledegradation of the marine environmentand to authorize imposition of effluentlimitations, including a prohibition ofdischarge, if necessary, to ensure thisgoal.

Offshore oil and gas facilities mayalso be required to prepare andimplement spill prevention control andcountermeasure (SPCC) plans underSection 311(j) of the Act. Theserequirements are set forth at 40 CFR Part112.

V. Overview of the Industry

A. Industry Profile

The offshore segment of the oil andgas extraction point source categorycovers those facilities located off thecoast of the United States that areengaged in the production of crudepetroleum and natural gas, the drilling ofoil and gas wells, and oil and gas fieldexploration services. These facilities,such as exploratory rigs, drillingplatforms, and production platforms, areconsidered offshore if they are locatedin waters that are seaward of the innerboundary of the territorial seas, asdefined in Section 502 of the Act.

There are currently about 3900platforms producing oil and gas in U.S.offshore waters. This estimate covers allfederal and state leased tracts in theGulf of Mexico and along the coasts ofCalifornia and Alaska. In 1982 over 405million barrels of oil and 4.7 trillioncubic feet of gas with a market value ofalmost $23 billion were producedoffshore. These quantities represent 15percent and 25 percent, respectively, ofthe total oil and gas produced in theUnited States. The combined bonuspayments and royalties paid to theFederal government for offshore leasestotaled almost $10 billion in 1981.

The majority (98 percent) of existingU.S. operations are located in the Gulf ofMexico. However, exploration anddevelopment activities are expected toexpand in the California, Alaska, and

-Atlantic Coast regions. For example,large potential petroleum reserves havebeen discovered at Point Arguello,California and in the Beaufort Sea,Alaska. Results of exploration drilling to

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date for the Atlantic outer continentalshelf (OCS) areas and the Gulf ofAlaska have not demonstratedsignificant petroleum reserves. The lackof geologic data to confirm the presenceof economically recoverable oil or gasmake development projections for theseareas less certain.

Offshore drilling activity varies fromyear to year depending on such facforsas hydrocarbon market conditions, stateand federal leasing programs, reservoirdiscoveries, and the strategic planningdecisions and financial health ofcompanies within the industry. In 1981there were almost 1500 wells drilledoffshore, culminating a steady upwardtrend throughout the 1970's. The averagenumber for the period 1972-82 isapproximately 1100 wells per year.Drilling rig utilization declined in 1982,and activity is not expected to improvesignificantly for some time, especiallywith the current downturn in crude oilprices.

EPA estimates that approximately 833new source oil and gas platforms will beconstructed between 1986 and the year2000 in offshore U.S. waters. Today'sproposed regulation distinguishesbetween oil facilities and gas facilitiesin the following manner. A gas facilityconsists of only gas wells. An oil facilityconsists of one or more oil wells, butcould also have gas wells. Definitions inSection 435.11 in today's proposedregulations present these distinctions.

B. Exploration, Development, andProduction

Exploration, development, andproduction activities generate wastedischarges that include produced water,deck drainage, drilling fluids, drillcuttings, well treatment fluids, producedsand, and sanitary and domestic wastes.

Exploration activities are thoseoperations involving the drilling of wellsto determine the nature of potentialhydrocarbon reservoirs. Theseoperations are usually of short durationat a given site, involve a small numberof wells and are generally conductedfrom mobile drilling units. Dischargesare composed principally of drillingfluids and drill cuttings.

Development activities involve thedrilling and completion of productionwells once a hydrocarbon reserve hasbeen identified. These operationsusually involve a large number of wellsand are typically conducted from a fixedplatform. Discharges are composedprincipally of drilling fluids and drillcuttings.

Production activities begin as eachwell is completed during thedevelopment phase. The productionphase involves active recovery of

hydrocarbons from producingformations. Development andproduction activities may occursimultaneously until all wells arecompleted and reworked. Duringproduction, discharges a'e composedprincipally of produced water and alsodrilling fluids and drill cuttings whileconcurrent development is in progress.The discharge of drilling fluids and drillcutting stops when development andwell reworking operations end.

C. Waste Streams

Produced water (brine) is brought upfrom the hydrocarbon-bearing strataalong with produced oil and gas, andcan include formation water, injectionwater, and any chemicals addeddownhole or during the oil/waterseparation process.

Drilling fluids (muds) -are 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.

Drill cuttings are the solids resultingfrom drilling into subsurface geologicformations, and are bought to thesurface of the well in the drilling fluidsystem.

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 alsoconsidered to be well treatment wastes.

Produced sand consists of the slurriedparticles used in hydraulic fracturingand the accumulated formation sandsgenerated during production.

Sanitary wastes originate from toiletsand domestic wastes originate from,sinks, showers, laundries, and galleyslocated on drilling and productionfacilities.

VI. Summary of MethodologyIn developing effluent regulations for

this industry segment, EPA first studiedthe industry to determine whetherdifferences in factors such as productionmethodology, location and type ofoperation, size and age of facility, andwaste constituents require separatelimitations and standards for differentsegments of the category. This studyinvolved an evaluation of how thesefactors affect raw waste loads, and theidentification of raw waste and treatedeffluent characteristics, includingsources and volumes of waste streams.

The Agency then determined the wasteconstitutents, including toxic pollutants,which should be considered for effluentlimitations guidelines and standards ofperformance.

EPA also identified both actual andpotential control and treatmenttechnologies that can be applied withineach industry segment. The Agencycompiled and evaluated both historicaland newly generated data on theperformance and operational limitationsof these technologies. In addition, EPAconsidered the impacts of thesetechnologies on air quality, solid wastegeneration, and energy requirements.

The Agency also estimated capitaland annual costs associated with eachcontrol and treatment alternative. Ingeneral, unit process costs were derivedby applying data on production andwaste characteristics for model facilitiesto unit costs developed for each controland treatment process. These unitprocess costs were added together toyield a total cost for each treatmentlevel. The Agency was then able todetermine total industry costs, evaluatethe costs of applying alternativetechnologies, and assess the economicimpacts of compliance for eachregulatory option considered.

Consideration of these factorsenabled EPA to classify the variouscontrol and treatment technologies as abasis for NSPS, BAT, and BCTregulations. The proposed regulations,however, do not require the applicationof any particular technology. Rather,they require compliance with effluentlimitations and standards representativeof the proper operation of these orequivalent technologies.

VII. Data Gathering Efforts

A. Existing Information

After the proposed NSPS werewithdrawn in 1980 in accordance withthe Court Order in NRDC v. Castle, theAgency conducted and assessment ofexisting information related to pointsource discharges from the offshoresegment of the industry. This includedprofiles of current and projectedoffshore drilling and productionactivities, regulatory history andenforcement status, wastecharacterization, existing and potentialcontrol and treatment technologies, andthe cost, energy and non-water qualityimpacts of pollution control. Existingdata were assembled through contactswith EPA regional offices, other Federaland State government agencies, industryassociations, industry representatives,third party oil transmission pipelinecompanies, solid waste dump site

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operators, drill cuttings washersuppliers, equipment manufacturers, andvarious technical publications.

B. Additional Data Collection

Several areas were identified thatrequired further study to support thereproposal of effluent limitationsguidelines and standards. Theseincluded an evaluation of prioritypollutant levels in produced waterdischarges, an evaluation of alternativecontrol and treatment technologies forreducing the discharge of prioritypollutants, a characterization of drillingfluids and additives presently in use, aninvestigation of alternative disposalpractices for drilling fluids and drillcuttings, an assessment of the impactsof discharging drilling and productionwastes to the marine environment ingeneral, and updated projections on thelocation, size and configuration of newsources.

C. Sampling and Analytical Programs

The sampling and analysis programsconducted for this rulemaking havefocused on produced water and drillingfluids and cuttings, and on the toxicpollutants designated in the CleanWater Act. However, EPA sampled andanalyzed wastes in the offshoresubcategory for certain conventionaland noncoventional pollutants as wellas inorganic and organic toxicpollutants. Analyses for prioritypollutants were based on a number ofthe proposed analytical methods (44 FR69464 (December 3, 1979); 44 FR 75028(December 18, 1979]). The finalanalytical methods were published onOctober 26, 1984 (49 FR 43234).

1. Produced Water

The Agency's initial effort toinvestigate priority pollutants inproduced water consisted of apreliminary screening survey conductedat six production platforms in the Gulfof Mexico during 1980. Results obtainedby using the standard proceduresproposed by EPA at that time indicatedthe presence of toxic organics andmetals. However, produced waters arebrines containing significantconcentrations of dissolved salts. Thebriny nature of this waste streamrequired the Agency to develop modifiedor unique analytical methods.Representatives of the OffshoreOperators Committee (OOC), theAmerican Petroleum Institute, and EPAcooperated in a joint effort in 1981 todevelop analytical protocols to measuretoxic pollutants in produced water.

During the first of a two-phaseanalytical program, produced watersamples were collected at two

production platforms in the Gulf ofMexico and sent to several Agency andindustry laboratories for comparativetesting. Final analytical protocols wereestablished employing standards purgedfrom ten percent sodium chloride brines,isotope dilution gas chromatography/mass spectrometry (GCMS) for analysisof volatile organic pollutants, continuousand/cr acid/neutral extraction andfused silica capillary column isotopedilution GCMS for analysis ofsemivolatile organic pollutants, andstandard addition flame atomicabsorption for metals analysis.

The second phase of the analyticalprogram was conducted with the use ofestablished protocols to confirm thepresence and further quantify theconcentrations of toxic pollutants inproduced water discharges at 30production facilities in the Gulf ofMexico. Selected conventioral and non-conventional parameters were alsoinvestigated. Samples were taken ofinfluents to and effluents from producedwater treatment systems during visitsthat ranged from one to three days atindividual sites. Strict adherence tospecified collection and qualityassurance procedures was maintainedthroughout the program. Additionalsamples were collected for independentanalyses sponsored by the OOC.

Priority pollutant sampling effortshave also been conducted at Alaska andCalifornia sites. Produced watersamples were collected from bothoffshore and onshore tieatment facilitiesat Cook Inlet and Prudhoe Bay in Alaskaand from three offshore productionplatforms in California's Santa BarbaraChannel.

2. Drilling Fluids

Another program was initiated by theAgency for this rulemaking to evaluatethe characteristics of water-baseddrilling fluids. Such fluids, or muds,include a variety of compositions usedas aids in drilling and stabilizing aborehole in the earth.

One objective of this on-goingprogram is to examine the testprocedures that are being proposedtoday as analytical methods applicableto this industrial subcategory formeasuring acute toxicity and fordetecting the presence of diesel oil inmud discharges. A second objective is toevaluate test results derived from theseand other Agency approved analyticalprocedures in the development ofeffluent limitations guidelines andstandards.

The first phase of this programinvolved the selection and specificationof test muds. The Agency's intent was toselect a group of the more commonly

used water-based mud formulations fortesting purposes. In doing so, theAgency relied upon informationgathered during the development ofNPDES permits issued in 1978 tooperators drilling on leases in theAtlantic Ocean. Eight basic mud typeswere defined during the Mid-AtlanticBioassay Program conducted by theAtlantic Ocean permittees incooperation with EPA Region I! and theOffshore Operators Committee (OOC).These eight generic mud types wereselected to encompass virtually allwater-based muds, exclusive ofspecialty additives, used on the outercontinental shelf. The components ofeach mud type were identified, andallowable concentration ranges for eachcomponent were specified, as presentedin Appendix B to this preamble.Bioassay test were conducted as apermit condition, and results of the Mid-Atlantic Program indicated that all eightgeneric muds demonstrated relativelylow toxicity. Under their NPDESpermits, operators were allowed todischarge muds that complied withthese specifications. This generic fluidconcept has been employed by otherEPA regional offices in the permittingprocess.

Since these eight generic mud typeswere considered to be operationallysatisfactory for the majority of offshoredrilling situations, the Agency selectedthe same mud compositions forinvestigation under the BAT and NSPSregulation development program.However, it was determined that, forregulation development, tests would bemore appropriately conducted on mudmixtures with components at the upperlimits of the allowable concentrations.Laboratory-prepared muds, based on theeight generic fluid formulations withmost components present at the upperlimits of allowable concentration, wereobtained from the Petroleum EquipmentSuppliers Association (PESA) in mid-1983. Samples of these formulationswere sent to EPA laboratories forchemical, physical, and biologicaltesting. Bioassay data collected over thepost five years by both government andindustry sponsored studies on the acutetoxicity of drilling fluids wereconsidered unsatisfactory as a basis forestablishing effluent limitations becauseof non-standard testing procedures anda high degree of variability amongtesting laboratories. The Agencytherefore developed a standard methodfor measuring acute toxicity of drillingfluids for this industrial subcategory(see Appendix 3 of the proposedregulation). Toxicity tests were thenconducted at EPA's Environmental

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Research Laboratories in Gulf Breeze.FL, and Narragansett, RI using thestandard bioassay procedure beingproposed in today's rulemaking.Analyses for oil content, biochemicaloxygen demand, chemical oxygendemand, total organic carbon, andprinrity pollutants excluding pesticideswere also performed at EPA contractlaboratories, along with the static sheentest being proposed today (Appendix 1of the proposed regulation).

To examine the characteristics of oilcontaminated muds, the Agency alsoobtained, through PESA and OOC,samples of two of the generic mudformulations spiked with variousamounts of mineral and diesel oils. Thetwo mud types selected were those lhatare most often used in drilling situationsthat require oil additives. The sameanalytical procedures were used to testboth the spiked and unspikedformulations.

One drilling fluid constituent that is afocus of concern is diesel oil, which istypically used as the primary componentin conventional oil-based drilling fluids,and is a fuel oil readily availableoffshore for use as a spotting fluid andlubricating agent in water-based muds.Research sponsored by both industryand government agencies has shownthat diesel oil contributes significantlyto the acute toxicity of such fluids. Toadd to the information already availablein the literature on the chemical makeupof diesel oil, the Agency gathered andtested samples of commerciallyavailable diesel fuels and a diesel mudadditive from an offshore drillingoperation in the Gulf of Mexico.Samples were analyzed for the organicpriority pollutant compounds using gaschromatography/mass spectrometry.Gas chromatography methods are alsobeing used to determine the presence ofdiesel oil in drilling fluids.

The Offshore Operators Committee isalso conducting a program to collectdata on the organic constituents ofdiesel and mineral oils used as drillingfluid additives. The Agency isparticipating in this program which willexamine the differences in chemicalcomposition and toxicity between dieseland mineral oil, and evaluate methodsfor measuring the diesel content ofdrilling fluids.

Another major constituent of drillingfluid systems is barium sulfate.commonly called barite. a mineral usedprimarily as a weighting agent to controldownhole pressures. Commercial formsof barite can contain various impurities.including toxic metals. To investigatethe presence of these contaminants, theAgency obtained samples of barite fromfour different sources and analyzed

them for priority pollutant metals. TheAgency intends to continue its survey ofthe quality and availability ofcommercial barite stocks.

EPA will continue to evaluate theproposed Drilling Fluids Toxicity Test.Static Sheen Test and the gaschromatography method for detectingthe presence of diesel oil. The Agencyplans to conduct interlaboratoryvalidation programs before thepromulgation of final regulations todetermine the precision and accuracy ofthese methods.

3. Drill Cuttings

The discharge of oil and other mudconstituents that adhere to or are mixedwith waste cuttings is the primaryconcern in the drill cuttings wastestream. The data gathered on the qualityof mud compositions were used toassess the expected effects of thedischarge of contaminated drill cuttingsto the ocean. In addition, informationwas obtained from suppliers of varioustypes of cuttings washer systems onprojected washer performance andtreatment costs. Selected samples of oilcontaminated drill cuttings before andafter washing were obtained forscreening purposes and tested for thesame conventional, nonconventional,and some priority pollutant parametersthat were investigated during the drillingfluids program.

4. Other Waste Streams

The Agency did not perform any newsampling or analytical programs fordeck drainage, sanitary, domestic,produced sand, and well treatmentfluids waste streams. Today's NSPS,BAT, and BCT proposed regulations forthese waste streams are based uponinformation collected during thedevelopment of the existing BPTregulations. Effluent limitations andstandards for certain toxic,conventional, and nonconventionalpollutants are being reserved for certainof these waste streams, as describedbelow, pending additional datacollection by the Agency.

D. Environmental Effects InformationCollection

The Agency has obtained informationfrom numerous sources regarding thegeneral environmental effects ofdischarges from offshore oil and gasplatforms. In November of 1982, EPAissued a draft report entitled, InterimFinal Assessment of Environmental Fateand Effects of Discharges from OffshoreOil and Gas Operations whichsummarized recent literature on theeffects of produced water, drilling fluids,drill cuttings, deck drainage and

sanitary wastes. The Agency distributedthe report for comment to someenvironmental organizations andindustry groups. On April 19, 1983, theAgency met with the Offshore OperatorsCommittee (OOC) in Houston, Texas todiscuss their comments on this report.

Subsequent to the issuance of thisreport, the Agency investigated otherdata sources on produced waterincluding an API report titled Effects ofOilfield Brine Effluent on BenthicOrganisms in Trinity Bay, Texas (APIPublication No. 4291) and a more recentdraft report titled Ecological Effects ofProduced Water Discharges fromOffshore Oil and Gas ProductionPlatforms (API Project No. 248). Otherreports on drilling fluids and cuttingswere also reviewed which include,Drilling Discharges in the MarineEnvironment by the National ResearchCouncil and Results of the DrillingFluids Research Program Sponsored bythe Gulf Breeze EnvironmentalResearch Laboratory, 1976-1984 andTheir Application to HazardAssessment (EPA Publication 600/4-84-0551.

In response to comments on the draftenvironmental assessment, the Agencyhas also summarized findings from otherfield studies pertinent to this regulationin the final environmental assessment.This assessment, titled Assessment ofEnvironmental Fate and Effects ofDischarges From Offshore Oil and GasOperations, is included as supportingdocumentation for today's proposedregulations and supersedes the draftassessment of November 1982. Inaddition to the discussion of the fieldstudies and other reports, this finalassessment discusses the results fromthe PLUME model which was developedby EPA's Corvallis EnvironmentalResearch Laboratory. This modelpredicts dilution, trap depth and depthof maximum penetration of the producedwater discharges.

The Agency has also investigated thefollowing: (1) biocides in use onplatforms and rigs; (2) commerciallandings of fish and invertebrates andlevel of effort statistics for the Gulf ofMexico; (3) marine species distributionsfor the United States; and (4) potentialimpacts from barite discharges. An EPAreport on biocides titled Biocides in Us6on Offshore Oil and Gas Platforms andRigs is included in the rulemakingrecord and referenced in theenvironmental assessment. The otheranalyses'are also summarized in thefinal environmental assessmentsupporting the proposed regulations.

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E. Economic Information Collection

The Agency obtained most of theeconomic data from a variety ofsecondary sources. Department of theInterior publications providedinformation on offshore leasing,platform development, production andincome. Department of Energypublications were used for informationon energy development, production andprice. Annual and 10-K reports andindustry trade publications were used toconstruct financial profiles of energydevelopment companies. In addition tothe above sources, a number of industryspecialists in both the public and privatesector provided data and opinions ontechnical and economic issues.

VIII. Waste CharacterizationThe major sources of waste generated

from offshore exploration, development,and production activities aresummarized in Section V. Pollutantparameters of concern include oilcontent (oil and grease, free oil, oil-based drilling fluids, diesel oil), organicand inorganic priority pollutants, acutetoxicity, residual chlorine, and floatingsolids. The Agency's effort to developeffluent limitations and standards forthis rulemaking focused on producedwater, drilling fluids, and drill cuttings.

A. Produced WaterWater brought up from hydrocarbon-

bearing strata with petroleum liquidsand natural gas includes brine trappedwith oil and gas in the formation andwater injected into the reservoir toincrease productivity. Such producedwater is the major source of wastewaterfrom offshore production operations.Data from a recent survey by theOffshore Operators Committee indicatethat more than 1.5 million barrels perday of produced water were dischargedto state and federal waters of the Gulf ofMexico in 1983. The percentage of waterin the total fluid production from areservoir ranges considerably, but'generally increases with the age of awell. Although produced waterdischarge rates vary widely, it has beenfound that, on the average, gas wellsgenerate considerably less water thando oil wells. Data gathered by theOffshore Operators Committee showthat, for the Gulf of Mexico OCS in 1983,the average produced water dischargefrom a gas production well is about tenpercent of that discharged by an oilproduction well.

Produced water contains anabundance of chlorides and dissolvedsolids in concentrations several timesgreater than in seawater. Significantconcentrations of oil and grease,

suspended and settleable solids, anddissolved hydrocarbons are alsopresent.

The analytical data obtained on thepresence and concentration of prioritypollutants in produced water confirmsthe presence of several of thesepollutants in both untreated and BPT-treated effluents. The results of EPA'ssurvey of produced water dischargesfrom 30 production platforms in the Gulfof Mexico described above show that, of88 organic priority pollutants analyzedfor, benzene, ethylbenzene,naphthalene, phenol, toluene, and 2,4-dimethylphenol were detected in most ifnot all of the 79 samples tested. Bis(2-ethylhexyl) phthalate, anthracene, andphenanthrene were found somewhatless frequently, but in more than half ofthe samples analyzed. Twenty-one ofthe organic priority pollutants weredetected at significantly lowerfrequencies (less than 30 percent), and58 of the organic priority pollutants werenever detected.

Of the seven priority pollutant metalsanalyzed in the same study, zinc wasthe only metal detected at quantifiablelevels in the majority of samples (morethan 80 percent). Copper, nickel, lead,cadmium, and silver were detected attrace levels at significantly lowerfrequencies. Chromium was not detectedin quantifiable amounts.

During a 1980 survey of 10 productionplatforms in the Gulf of Mexicosponsored by the Agency's Office ofResearch and Development, andsummarized in a report titled OilContent in Produced Brine on TenLouisiana Production Platforms (the"Crest" report), several other chemicalswere found in produced water. Thesechemicals include biocides, coagulants,corrosion inhibitors, cleaners,dispersants, emulsion breakers, paraffincontrol agents, reverse emulsionbreakers and scale inhibitors. EPA hasdetermined that most of the biocidesregistered for use in this industry are notpriority pollutants. The prioritypollutants identified as activeingredients in biocides registered for usein this industry were acrolein andpentachlorophenol. At the present timeno halogenated phenol compounds, suchas polychlorinated biphenyls andpentachlorophenol, may be used in anyoperational activity. This is based on anoperating order published by U.S.Geological Survey (see 44 FR 39031).

Analytical results also confirm thefindings of the study supporting BPTthat significant levels of oil and greaseare found in untreated produced water.In the 30-platform study, the median oiland grease removal from produced

water by existing treatment systemswas estimated at 63 percent. In fact, theAgency determined that, with improvedoperation and maintenance practices,BPT treatment facilities can achievemeasurable additional reductions in oiland grease (see Section X). The effectsof BPT treatment on the other chemicals.(non-priority pollutants) found inproduced water are incidental becausethe BPT equipment is not designed toremove these chemicals, which areadded directly to the production ortreatment systems in many instances(biocides, corrosion inhibitors,coagulants, etc). Generally, nomeasurable reduction in the levels ofsuch chemicals is expected from existingBPT-type treatment systems.

Analytical results were compared tothose reported by the OffshoreOperators Committee (OOC) fromduplicate samples taken at 6 of the 30offshore platforms sampled by EPA. Thequantitative concentrations measuredby the industry differed somewhat fromthose reported by EPA contractlaboratories. However, the industry datadoes confirm the presence of prioritypollutants in produced water; that BPTtreatment reduces the level of some ofthese priority pollutants; and thatpriority pollutants are still beingdischarged to waters of the UnitedStates after existing treatment.

For purposes of determiningappropriate limitations and standards,the Agency categorized the pollutantspresent in produced water wastestreams as follows. First, the prioritypollutants, organics and metals are"toxic" pollutants being designated assuch pursuant to Section 307(a)(1) of theAct. It would be appropriate to set BATlimitations for these pollutants as wellas for NSPS. Then the other chemicals,such as those contained in biocides,coagulants, corrosion inhibitors,cleaners, dispersants, emulsionbreakers, paraffin control agents,reverse emulsion breakers and scaleinhibitors which have not beenidentified as containing designated"toxic" pollutants, would be considerednonconventional pollutants subject toBAT limitations and NSPS. Anypollutants in these products which havebeen designated "toxic pollutants"would be subject to BAT and NSPStoxic limitations and standards. Finally,the oil and grease present in producedwater would be considered aconventional pollutant subject to BCTlimitations and NSPS.

B. Drilling Fluids

Drilling fluids, or muds, aresuspensions of solids and dissolved

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materials in a base of water or oil thatare used in rotary drilling operations tolubricate and cool the drill bit, carrycuttings from the hole to the surface, andmaintain hydrostatic pressuredownhole. Oil-based drilling fluids arethose in which oil, typically diesel,serves as the continuous phase withwater as the dispersed phase. Suchfluids contain blown asphalt and usuallyone to five percent water emulsified intothe system with caustic soda orquicklime and an organic acid. Silicate,salt, and phosphate may also be present.Oil-based muds are more costly andmore toxic than water-based muds, andare normally used only for particularlydemanding drilling conditions. Lu water-based muds, water is the suspendingmedium for solids and is the continuousphase, whether or not oil is present.Water-based muds are more commonlyfor use offshore and were focused uponin the development of today'srulemaking.

Drilling fluids are specificallyformulated to meet the physical andchemical requirements of a particularwell. Mud composition is affected bygeographic location, well depth, androck type, and is altered as well depth,rock formations, and other conditionschange. The number and nature of mudcomponents varies by well, and severalproducts may be used at any given timeto control the properties of a mudsystem.

A survey was conducted by theAgency of drilling muds used in recentlycompleted wells in the Gulf of Mexico.Its purpose was to obtain an accurateestimate of the types and quantities ofmud components used in currentpractice. Chemical inventories of basecomponents and specialty additivesused downhole were collected for 74exploratory and development wellsdrilled offshore since 1981. These wellswere representative of drilling activitiesin 55 lease areas throughout Louisianastate waters, Texas state waters, andfederal OCS waters.

Survey findings indicate that fourkinds of material, excluding water,account for about 90 percent by weightof all components used, namely barite,clays, lignosulfonates, and lignites.Other components, including lime,caustic soda, soda ash, and a multitudeof specialty additives, are used asdictated by well requirements. Thequantities of components used werefound to vary considerably from well towell, but certain trends were observed.Wells in federal outer continental shelfwaters required, on average, moredrilling muds and specialty additivesthan did wells in state waters. Also,

exploratory wells required more drillingmud and specialty additives than diddevelopment wells. Average total mudconsumption for The surveyed wellsamounted to 3.1 million pounds perexploratory well and 0.8 million poundsper development well.

Direct discharges of drilling fluids aregenerally in bulk form and occurintermittently during well drilling. Lowvolume discharges are made to maintainproper solids levels in mud systems.High volume discharges occur duringchanges in mud types, for dilutionpurposes, and when mud tanks areemptied at the end of drilling operationsif fluids are not being reused. Suchdischarges can occur several timeswhile drilling a well, and can total 2,000barrels or more for each drilling fluidsystem changeover.

As discussed in Section VII, theAgency selected eight generic, water-based mud types for investigation duringthe development of today's proposedrulemaking. Chemical, physical, andbiological analyses were conducted onlaboratory-prepared samples of theseeight formulations, both with andwithout oil additives. Samples were hot-rolled prior to testing to simulate thedownhole pressures and temperatures towhich spent muds would be subjected.

Analtyical results indicate that noneof the organic priority pollutants weredetected in any of the base genericdrilling fluid formulations. However, 10of the 13 metals on the priority pollutantlist were found in detectable quantitiesin the generic formulations. Cadmiumand mercury, in particular, were presentin all muds tested, but at levels below Img/kg each.

Bioassay results indicate that theacute toxicity of the generic muds rangeconsiderably. No median effects (50percent mortality) were observed forthree of the eight mud types, whereasthe most toxic was found to be thepotassium/polymer mud. Its suspendedparticulate phase showed a 96-hr LC-50of 3 percent by volume (30,000 ppm), asmeasured by the proposed bioassay testmethod (Appendix 3 of today's proposedregulation).

Drilling fluid toxicity was found toincrease with the addition of mineral oil,and even more so with diesel oiladditions. These findings are consistentwith results of other research activitiesconducted at EPA's EnvironmentalResearch Laboratory in Gulf Breeze,Florida. The Agency will continue toinvestigate the toxicity of variousmineral oil additives to determine whichformulations are operationally adequatesubstitutes for the more toxic diesel oil

and result in the'least overall toxicity ingeneric drilling fluid formulations.

GC/MS analyses of diesel additives todate show the presence of organicpriority pollutants, including benzene,toluene, ethylbenzene, naphthalene, andphenanthrene. Limited analyses ofmineral oils to date also show thepresence of organics, including benzene.naphthalene, phenanthrene, andfluorene.

Static sheen tests were conducted onthe generic muds using the proposedmethodology. Free oil was not detectedin any of the eight base formulationsthat did not contain oil additives. Sheentests were also conducted on water-based muds that contained variousamounts of mineral and diesel oil. Thetwo generic mud types selected fortesting were those that are most oftenused in drilling situations that require oiladditives. Both mineral and diesel oiladditions were found to cause sheens ontest waters. However, water-basedmuds with diesel spikes producedsheens at lower spiking concentrations,as low as one percent by volume.

The Agency categorized the pollutantspresent in drilling fluids waste streamsfor purposes of determining appropriatelimitations and standards. First, thepriority pollutants, organics and metals,are "toxic pollutants" being designatedas such pursuant to Section 307(a)(1) ofthe Act. These toxic pollutants includethe mercury and cadmium in barite andthe organic pollutants listed abovewhich are present in the diesel andmineral oils which may be added todrilling fluids. Also, the large number ofspecialty additives which may be usedcan contain priority pollutants ornonconventional pollutants. It would beappropriate to establish BAT limitationsas well as NSPS for the toxic andnonconventional pollutants. Asdiscussed in greater detail in SectionXI.A.2, the Agency has proposedspecific numeric limitations on mercuryand cadmium, and a prohibition on thedischarge of free oil, oil-based drillingfluids, and diesel oil, which are allconsidered as "indicators" of toxicpollutants. Second, the oil and greasepresent in drilling fluids would beconsidered a conventional pollutantsubject to BCT limitations as well asNSPS.

C. Drill Cuttings

When circulating drilling fluid returnsto the platform from the well beingdrilled, it contains drill cuttings thathave been cut from the well bore by thebit. These cuttings range from micron-sized to coarse, sand- to pebble-likeparticles. The cuttings are coated with

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drilling fluid. Drilling fluid additives mayabsorb onto or be absorbed by thecuttings.

The drilling fluid from the welldischarges to a rig shale shaker wherethe cuttings are separated from thedrilling fluid. This separation step doesnot completely remove drilling fluidfrom the cuttings. Some drilling fluid andadditives remain on the drill cuttings.Therefore, the composition of thecuttings will be similar to the drillingfluid except for the downhole formationparticles, particle size distribution, andthe relative amounts of the variousdrilling fluid constituents.

Results of recent analyses by EPAcontract laboratories on drill cuttingsderived from the use of oil-based drillingfluids show oil and grease levels of up to136,000 mg/kg, chemical oxygen demand(COD) running as high as 270,000 mg/kg,and biochemical oxygen demand (BOD)as high as 8,000 mg/kg. The BOD valuesare artificially low as a result of theinhibition by oil. In addition, severaltoxic organic compounds, includingnaphthalene, acenaphthene,phenanthrene, 4-nitrophenol, N-nitrosodiphenylamine, pyrene, and bis(2-ethylhexyl] phthalate, and 10 of the 13priority pollutant metals were found inmeasurable quantities. These dataindicate the presence of toxic pollutantsin oil-contaminated cuttings, and thatorganic loadings due to the discharge ofsuch waste streams can be significant.

The Agency's approach to determiningthe appropriate limitations andstandards for drill cuttings is the sameas that used for drilling fluids since thedrilling fluids that adhere to the drillcuttings are the major concern. Thepriority pollutants present in the drillingfluids would be controlled by BATlimitations and NSPS that prohibit thedischarge of free oil and cuttings fromoil-based fluid systems. Theselimitations serve as indicators of thetoxic pollutants that could be present inthe drilling fluids adhering to the drillcuttings.

The conventional pollutant "oil andgrease" will be subject to a BCTlimitation and NSPS prohibiting thedischarge of free oil.

D. Deck DrainageDeck drainage results primarily from

precipitation runoff miscellaneousleakage and spills, and washdown ofplatform or drill ship decks and floors. Itoften contains petroleum-based oilsfrom miscellaneous spills and leakage ofoils and other production chemicalsused by the facility. It may also containdetergents from washdown operationsand discarded or spilled drilling fluidcomponents. For the reasons described

above, the Agency has identifiedpriority pollutant constituents of oil aspollutants of concern and has proposeda no discharge of free oil limitation asboth a BAT limitation serving as anindicator toxic pollutants and as a BCTlimitation for conventional pollutants.

E. Sanitary WastesThe volume and concentration of

sanitary wastes vary widely with time,facility occupancy, and operationalsituation. The wastewater primarilycontains body waste but, dependingupon the sanitary system for theparticular facility, other waste may becontained in the waste stream. Usuallythe toilets are flushed with fresh waterbut, in some cases brackish or sea wateris used.

The concentrations of waste aresignificantly different from those formunicipal domestic discharges, since theoffshore operations require regimentedwork cycles which impact wasteconcentrations and cause fluctuation inflows. Waste flows have been found tofluctuate up to 300 percent of the dailyaverage, and BOD concentrations havevaried up to 400 percent.

Waste flows may vary from zero forintermittently manned facilities toseveral thousand gallons per day forlarge facilities. Pollutants of concern arethe conventional pollutants fecalcoliform and floating solids and areproposed to be regulated for the BCTlevel of control. Fecal coliform would becontrolled by a residual chlorinelimitation.

F Domestic WastesDomestic wastes result from

laundries, galleys, showers, etc. Wasteflows may vary from zero forintermittently manned facilities toseveral thousand gallons per day forlarge facilities. Since these wastes donot contain fecal coliform, which mustbe chlorinated, they must only beground up so as not to cause floatingsolids on discharge. Thus, theconventional pollutant of concern isfloating solids which is proposed to beregulated for the BCT level of control.

G. Produced SandThe fluids produced with oil and gas

may contain varying amounts of sandand other particles such as scale, whichmust be removed from lines and vessels.This may be accomplished by opening aseries of valves in the vessel manifoldsthat create high fluid velocity around thevalve. The sand is then flushed througha drain valve into a collector vessel ordrum. Produced sand may also beremoved in cyclone separators when itoccurs in appreciable amounts.

Produced sand has been reported to begenerated at the rate of one barrel per2,000 barrels of oil.

The sand that is removed from theproduced fluids typically has a high oilcontent. The primary pollutant ofconcern in produced sand wastes is oil.Therefore, for the reasons discussedabove, the Agency has proposed nodischarge of free oil as a BAT limitationserving as an indicator of toxicpollutants. The no discharge of free oil isalso proposed as a BCT limitation onconventional pollutants.

H. Well Treatment Fluids

Well treatment fluids includechemicals used in acidizing andfracturing operations performed as partof remedial service work on old or newwells. Additionally, the fluids used to"kill" a well so that it can be servicedmay create wastes for disposal.

Spent acid and fracturing fluidsusually move through the normalproduction system and through thewaste water treatment systems.Therefore, the fluids do not appear as adiscrete waste source. However, theirpresence in the waste treatment systemcan cause upsets and a higher oilcontent in the discharged water. Liquidsused to kill wells are normally drillingmud, water, or an oil.

Coverage of well treatment fluids forall pollutants except free oil is reservedin this proposed rulemaking pendingcollection and analysis of sufficientanalytical data and information by EPA.However, to the extent any particularoffshore facility passes such wastesthrough the produced water treatmentsystem or commingles it with otherregulated wastes streams for discharge,the commingled well treatment fluidswould also be subject to the sameeffluent limitations as for the regulatedwaste stream(s).

IX. Industry Subcategorization

In many industries, factors whichaffect the ability of facilities to achievetechnology-based limitations varyamong groups of facilities. In such cases,EPA will establish different effluentlimitations guidelines or standards forthe various groups of facilities (i.e.,subcategories). Essentially,subcategorization allows the Agency tomore precisely tailor the requirements oftechnology-based limitations to thecapacity of a diverse industry.

The oil and gas extraction pointsource category currently includes fivesubcategories: offshore, onshore,coastal, agricultural and wildlife wateruse, and stripper (40 CFR Part 435).Today's proposal covers only the

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offshore subcategory. This subcategoryis applicable to those facilities engagedin field 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 seasas defined in section 502 of the Act.

The studies in support of previouslyproposed NSPS and BAT and final BPTregulations for the oil and gas extractionindustry concluded that three majorfactors-geographic location, type offacility, and waste water disposition-are the bases for subcategorization ofthis industry. (41 FR 44945, 44 FR 22069).

In developing today's proposed NSPS,BAT, and BCT regulations for theoffshore segment of this industry, EPAevaluated characteristics of wells,platform waste effluents, availabletreatment technologies, and platformoperations to determine if it wasappropriate to modify the BPTsubcategorization scheme. EPA found nobasis upon which to change the existingsubcategorization for the offshoresegment. The Agency concluded that theexisting single subcategory for theoffshore segment was also appropriatefor today's proposed NSPS, BAT andBCT regulations. It should be noted thatwhile the Agency determined that it wasnot necessary to change the existingoffshore subcategorization, the proposedNSPS includes different produced waterstandards based on the type ofoperation and location of the facility.(See § 435.15 of today's proposedregulations.)X. Control and Treatment Technologies

A. Current PracticeBPT regulations established for the

offshore segment of the industry arefocused primarily on the control of theoil content of waste streams that aredischarged to the ocean.

1. Produced WaterExisting technologies for the on-site

removal of oil and grease from producedwater discharges include gas flotation,parallel plate coalescers, loose orfibrous media filtration, gravityseparation, and chemical addition toassist oil-water separation. On-sitedisposal methods from offshoreproduction platforms include free falldischarge to the ocean, discharge belowthe water surface, and reinjection into asubsurface formation. As an alternative,some production sites transportproduced fluids by pipeline to shorefacilities for oil-water separation anddisposal.

The removal of priority pollutants inBPT treatment systems is a complex

phenomenon that has not been fullyexplored. While the sampling dataindicated quantifiable reductions ofnaphthalene, lead, and ethylbenzeneafter BPT treatment (i.e., by oil waterseparator technology), the presence ofsignificant levels of priority pollutants(e.g., naphthalene and ethylbenzene) inall effluent 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, thereceiving formation may not be the sameformation from which produced fluidswere extracted. Secondary recovery orpressure maintenance is when producedwater (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 prior toinjection may be necessary and 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 may be added to thewater to reduce or prevent scaling andcorrosion of the injection equipment.The type and amount of treatmentdepends primarily on the properties ofthe receiving formation and wastewatercharacteristics.

2. Drilling Fluids

Disposal of drilling fluids, as currentlyregulated by BPT, prohibits thedischarge of free oil that would.cause afilm or sheen upon or a discoloration ofthe surface of the receiving water. Thedischarge of drilling fluids is regulatedby NPDES permits under section 402 ofthe Clean Water Act and by Departmentof the Interior lease sale stipulationsunder the Outer Continental Shelf LandsAct. Water-based drilling fluids aredischarged directly to the oceans unlessthe fluid has been contaminated withoil. Water-based fluids are discharged atthe surface, into the water column, orshunted to the ocean bottom through apipe. Where water-based drilling fluidsare contaminated with oil to the extentthat they would cause a sheen upondischarge, current BPT regulationsprohibit their discharge; compliancewith the prohibition is by transportationof the spent fluids to shore for recoveryor land disposal. When oil-based drillingfluids are used offshore, the fluids are

not discharged, but are returned to shorefor reconditioning and reuse or disposal.

3. Drill Cuttings

Existing practices for the handling ofdrill cuttings include: (1) on-site disposalof drill 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 discharged toa receiving water; and (3) transportationto shore for land disposal. Some cases ofdisposal of muds and cuttingscontaminated by oil have been reportedin the Gulf of Mexico by the MineralsManagement Service (MMS). MMS'sDistrict supervisors have issued at least13 letters since 1980 that list items ofnon-compliance (INC) involving oil indischarged muds and cuttings. MMSrequired the responsible operators toclean up the disposal sites where oilwas seeping to the ocean surface andcausing a sheen.

The cuttings are segregated from thedrilling fluid with a shale shaker andassociated separation equipment. If thecuttings contain no oil or levels of oilthat will not cause a sheen upondischarge, the cuttings are sluiced withsea water to the receiving water.However, if the levels of oil in thecuttings are such that a sheen wouldoccur if the cuttings were discharged tothe receiving water, the cuttings areeither washed prior to discharge ortransported to shore for land disposal.

Various types of cuttings washers areavailable. The basic process for thewashing of cuttings is similar for allcuttings washer systems that wereinvestigated. The process consists offirst exposing the cuttings to a washingliquid (water, water plus cleaningchemicals, or solvents). The "washed"cuttings are then processed to removethe working liquid and discharged to thereceiving water or transported to shorefor land disposal. The washing liquid isthen processed to recover the oilwashed from the cuttings and reused.Separated oil is directed to the oil-waterseparation system serving theproduction wells. Oil-coritaminatedwash fluids are either reused in the drillcuttings wash process, burned, ortransported to shore for disposal.

The greater the sophistication andcost of the cuttings washer system, themore efficient the oil removal. Allwasher systems investigated werereported to reduce oil content of drillcuttings to less than 10 percent, byweight. The more sophisticated systemsusing solvents are reported to reduce oilto less than 0.5 percent, by weight.Quantitative information on cuttings

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washer performance was not welldocumented in the information obtainedfrom suppliers.

4. Deck Drainage.Deck drainage is either collected and

treated separately for oil removal bygravity separation or is handled by theproduced water treatment system beforedischarge.

A commonly used treatmenttechnology for removal of free oils fromdeck drainage is oil-water separation.This is typically a gravity separationprocess, whereby the waste stream iscollected and diverted to a tank, pit,sump pile, or other vessel. Adequatevolume is provided in the vessel toprovide sufficient detention time for thefree oil and water to separate. The oillayer is then removed by decanting orskimming and returned to the productionprocess, and the water layer drawn offfor discharge. The majority of platformsin the Gulf of Mexico and offshoreCalifornia use gravity separationtechnology on the platform for treatmentof deck drainage. Some Californiaplatforms pipe deck drainage along withproduced water to shore for treatment.Alaska operations typically treat deckdrainage wastes on the 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 crank case 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 disposal or aretreated by water and/or solvent washesfor oil removal to prevent the dischargeof free oil.

6. Sanitary WastesSanitary wastes from offshore

facilities are usually treated at thesource by physical/chemical systems.Facilities that are manned continuouslyby ten or more people are required tomaintain a residual chlorineconcentration in the sanitary wastedischarge as close to 1 mg/I as possiblefor disinfection purposes. This chlorineresidual is achieved by introducingchlorine in flow dependent amounts.Chlorine is either supplied fromcommercial sources or may beelectrocatalytically generated fromseawater. This chlorine requirement isbased upon the use of U.S. Coast Guard

approved marine sanitation devices (40CFR Part 140) and is required by the BPTregulations.

7. Domestic WastesDomestic wastes at all facilities and

sanitary discharges from facilities thatare manned intermittently by nine orfewer people must be free of floatingsolids which is required by the BPTregulations. This is accomplished withthe use of shredders or screeningdevices.B. Additional Technologies Considered

The Agency considered the followingadditional control and treatmenttechnologies in the formulation oftoday's proposed regulations.

1. Produced WaterEPA evaluated each of the followi*-g

treatment technologies for NSPS. Thesetechnologies were considered forimplementation at offshore facilities,and onshore where produced water ispiped to shore for treatment.

(a) Improved Performance of BPTTechnology. EPA evaluated the costsand feasibility of improved performanceof existing BPT treatment technologiesto determine whether more stringenteffluent limitations for oil and greasewould be approp.-iate. This technologywould consist of improved operationand maintenance of existing BPTtreatment equipment (e.g., gas flotation,coalescers, gravity oil separation), moreoperator attention to treatment systemoperation, and possibly resizing ofcertain treatment system componentsfor better treatment efficiency.

Based upon statistical analysis ofeffluent data from facilities sampledduring the Agency's 30-platform survey,EPA determined that an oil and greaseeffluent limitation of 59 mg/I maximum(i.e., no single sample to exceed) cail beachieved through improved perfornanceof BPT technology. This limitation wouldsupersede the existing 72 mg/I BFT dailymaximum (average of four sahiples ii;one day). This limitation is suppoetcl byinformation presented in the reporttitled Potential Impact of Proposed EPABA T/NSPS Standards for ProducedWater Discharges From Offshore 01!and Gas Extraction Industry, (January1984), sponsored by the OffshoreOperator's Committee for the Gulf ofMexico. The Agency's analysis ofinformation from this study concludedthat at least 75 percent of existingoffshore operations in the Gulf ofMexico were already achieving oil andgrease levels of 59 mg/I (maximum) orless in produced water. In addition, theAgency analyzed produced watereffluent data from available discharge

monitoring reports (DMR's) submittedby operators of offshore productionfacilities in the Culf of Mexico. Theresults indicate that at least 60 percentof these facilities are presentlyachieving an oil and greaseconcentration of 59 mg/I or less (dailymaximum) in produced waterdischarges. Thus, the Agency concludedthat improved BPT performance toachieve greater reduction in oil andgrease warranted further considerationin the development of NSPS and BCT forproduced water.

(b) Filtration. EPA consideredfiltration as an add-on technology toBPT. The purpose of filtration is toremove suspended matter, includinginsoluble oils, from produced water. Thefiltration process is physical in natureand normally will not remove solublematerials. Because the majority of thepriority pollutants in produced water arein solution or in a soluble form, noquantifiable reductions in prioritypollutants are effected by filtrationtechnology alone. However, reductionsin conventional pollutants such as totalsuspended solids and oil and grease areexpected. These conclusions aresupported.by analytical results obtainedby EPA from sampling filtration systemsthat treat produced water.

While the Agency determined thatfiltration is technologically feasible toimplement on an industry-wide basis,EPA rejected filtration from furtherconsideration as a BAT treatmentalternative because it is not effective inreducing priority pollutant levels.However, because filtration is a feasibletechnology for controlling conventionalpollutants (i.e., oil and grease), theAgency concluded that filtrationwarranted further consideration indeveloping NSPS and BCT.

(c) Reinjection, Reinjectiontechnology for produced water typicallyconsists of injecting it under pressure tosubsurface strata or formations.Treatment of the waters prior toinjection is usually necessary. Suchtreatment may include removal of freeoils and suspended matter by oil-waterseparation and filtration technologies.The removal of suspended matter priorto injection is usually performed toprevent pressure buildup and plugging ofthe receiving formation or strata.Biocides and corrosion inhibitors aretypically added to the waters tominimize corrosion and scaling of theinjection equipment. Reinjectiontechnology results in no discharge tosurface waters, i.e., zero discharge.

EPA evaluated this technology forimplementation by both existing andnew platforms. While EPA found that

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reinjection is technologically feasibleand economically achievable forimplementation by new sources, theAgency currently lacks sufficientinformation on the technologicalfeasibility and costs of retrofitting thismodel technology on a national basis forexisting facilities. This is due touncertainty of retrofit requirements forexisting platforms, which can includeeither construction of additions toexisting platforms or construction ofauxiliary platforms to accommodateinjection well slots and other injectionequipment.

(d) Carbon Adsorption. EPAconsidered carbon adsorption as anadd-on technology to BPT. The purposeof carbon adsorption would be to reducethe levels of priority organic pollutantsin produced water. EPA determined thatcarbon adsorption is presentlytechnologically infeasible to implementin this industry segment. This is becauseof the unknown effects that the brine-like nature of produced waters has onthe adsorption process, the lack ofperformance information in either theliterature or on a pilot or full-scale basis,and the disproportionately high costs toeven attempt to implement thistechnology on a national basis for thisindustry segment. Therefore, EPArejected carbon adsorption from furtherconsideration for NSPS and BAT.

(e) Biological Treatment. Biologicaltreatment of produced water wasconsidered as an add-on technology toBPT. The purpose of biologicaltreatment would be to reduce the levelsof priority organic pollutants and oil inproduced water. The available literatureon the treatment of wastewatercontaining high dissolved solids levels(such as produced water) indicatessevere problems with acclimating andmaintaining biological cultures to treatsuch briny wastes. The dissolved solids(measure of brine content) levels inproduced water are significantly higherthan levels at which any biologicallyactivated treatment system has beenused or even tested. Therefore, EPArejected.bological treatment from furtherconsideration for NSPS and BATbecause it is, at present, technologicallyinfeasible to implement on a nationalbasis for this industry segment.

(f) Chemical Precipitation EPAevaluated chemical precipitation as anadd-on technology to BPT for thereduction of priority pollutant levels inproduced water. Chemical precipitationtechnology can be effective in removingsoluble metallic ions by their conversionto an insoluble form with subsequentremoval be sedimentation (settling) orfiltration. The Agency evaluated the

efficacy of hydroxide (lime) and sulfideprecipitation, the two most likely typesof chemical treatment for this type ofwastewater. The Agency's analyticaldata on produced water prior totreatment indicated that zinc is the onlypriority pollutant metal found in themajority of samples of produced waterdischarges. Hydroxide and sulfideprecipitation were determined to effectvirtually no removal of zinc from BPT-treated produced water because of thelow concentrations of zinc in the BPTeffluent. Sulfide precipitation was alsofound to cause potentially seriousproblems with its use, includinggeneration of sulfide gases and toxicityof the treatment chemicals. In addition,with the use of chemical precipitation,large settling facilities would berequired to effect proper treatment andthen the large quantities of sludgegenerated would have to be disposed.Thus, EPA rejected chemicalprecipitation from further considerationfor NSPS and BAT on a national basisfor this industry segment because ofoperational problems with implementingthe technology and nonquantifiablereductions of priority pollutant'metalslevels in BPT-treated produced water.

2. Drilling Fluids.EPA evaluated each of the following

practices with respect to offshoredrilling operations.

(a) Clearinghouse/Toxicity Approach.The concept of generic muds is thatoperationally satisfactory mud systemscan be formulated with constituents thatare less environmentally harmfull thanmany currently used drilling mudcomponents. This concept is based onthe stipulation of general, water-basedmud types, classified by majorcomponents, which are consideredacceptable for discharge.

One such approach to the control ofdrilling fluid discharges during drillingactivities was developed cooperativelyin the late 1970's by EPA Region II andthe Offshore Operators' Committee.Operators working on leases in theBaltimore Canyon had applied to RegionI for NPDES permits to dischargedrilling wastes. At the time, the Agencygrouped all drilling muds into two broadcategories, oil-based and water-based,and did not recognize differences amongwater-based systems. Region IIprohibited the discharge of all oil-baseddrilling fluids, but needed a means ofclassifying and controlling the dischargeof water-based systems which couldcontain numerous possiblecombinations of constituents.

As an alternative to requiring eachmid-Atlantic permittee to performbioassay and chemical tests every time

a mud discharge occurred, Region IIallowed a joint testing program to coverall muds selected for use. Eight genericmud types were identified whichencompassed virtually all water-basedmud compositions used on the OuterContinental Shelf. (See Appendix B ofthis preamble). Concentration ranges ofvarious base constituents were specifiedto allow sufficient flexibility inperformance characteristics andoperational needs. A bioassayprocedure was developed and testswere conducted on samples of fieldmuds representing each of the eightbasic mud types. Results of the Mid-Atlantic Bioassay Program indicatedthat the eight selected mud typesdemonstrated relatively low toxicity.Operators were then allowed todischarge drilling fluids of the eighttypes, including certain approvedspecialty additives, without conductingadditional tests. This generic mudconcept has since been incorporatedinto permits issued by other EPAregional offices.

(b) Product Substitution/ToxicityApproach. This option involves a seriesof product substitutions to reduce oreliminate the discharge of prioritypollutants and minimize the toxicity ofdischarged drilling fluids and additives.Product substitutions include: use ofgeneric (water-based driling fluid baseformulations instead of oil-based drillingfluids (as discussed in option (a) above),use of mineral oil instead of diesel oilfor lubricity and spotting purposes toreduce the toxic organics content ofdischarged fluids, use of barite with lowto non-existent toxic metalb content,and use of low-toxicity specialtyadditives. This option would alsoinclude a toxicity limitation (LC-50) tobe achieved when the drilling fluidsystem is discharged. The toxicitylimitation would be based upon the useof water-based drilling fluids toencourage their use.

(c) Zero Discharge. This option isbased upon the transport of spentdrilling fluids to shore for recovery,reconditioning for reuse, or landdisposal. This option would result in nodischarge of pollutants to surfacewaters.

3. Drill Cuttings

EPA evaluated the followingtreatment technologies with respect toimplementation at the facility.

(a) Mechanical Processes. Drillcuttings are typically separated from thedrilling fluid in a shale shaker or othersimilar device. However, quantities ofdrilling fluid, and oil and additives ifused, remain with the separated drill

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cuttings. The drilling mud is firstloosened from the cuttings either by apressure spray or by immersion in atank containing a wash solution andequipped with an agitator. The washsolution may be seawater, a water-based wash solution, or a closed-solventwash system. Sometimes a detergent isused to facilitate washing of thecuttings. A mechanical separation stepusually follows which separates thesolids, oils and additives from the washsolution. The separated oil andadditives may be returned to the drillingmud system. Wash solutions arerecycled, and the washed cuttings aretypically discharged overboard.

The performance of cuttings washersystems is measured in terms of residualoil remaining on the cuttings. Most ofthe washer suppliers claim that theresidual oil after washing will be lessthan 10 percent by weight and no sheenwill result from their discharge. Onewasher supplier provides a system thatdries the cuttings after washing to apowder-like form with claimed oilresiduals of 0.5 percent or less, byweight.

The mechanical washing process isthe most prevalent system in operationin the Gulf of Mexico, off the CaliforniaCoast and in the North Sea.

(b) Solvent Extraction System. In thisprocess, oil from the cuttings isextracted by a solvent, the cuttings areseparated from the solvent washsolution, and discharged to the sea. Oilis separated from the solvent by aproprietary process and the solventreused.

One supplier of solvent type washersystems claims that residual oil on thecuttings would not exceed 1 percent byweight and it may be-possible to reducethe oil content to a maximum of 0.2percent by weight. No solvent extractionunit is known, as yet, to be in full-scalefield operation. Therefore, thistechnology was not given furtherconsideration at this time.

(c) Vacuum Distillation. Vacuumdistillation of cuttings is basically a"mini-refinery" process where thecuttings are ground to a fine powder andfed to a vacuum retort. The retort isheated and a two-stage vacuum pumpremoves the evaporated water, oil andchemicals. The mixed vapor first flowsthrough a cyclone for solids separationand then to a vapor condenser. Thecondensed liquid (oil, water and somechemicals) is recycled in the mudsystem and the cuttings, in the form ofsolid residues, are dischargedoverboard.

The washer supplier claims that theamount of oil remaining on the cuttings

will be in the range of 100 to 500 ppm, byweight (i.e., less than 0.05 percent).

Three units have been manufacturedand sold for use in the United Kingdom.The operational history of this type ofunit has not been reported thus far.Therefore, this technology was not givenfurther consideration at this time.4. Deck Drainage, Sanitary Wastes,Domestic Wastes, Produced Sand

The Agency did not identify anycontrol and treatment technologies otherthan the current practices discussedabove.

5. Well Treatment FluidsThe Agency is reserving coverage of

NSPS, BAT and BCT for all pollutantsexcept free oil for this waste streampending additional data collection andanalysis.XI. Selection of Control and TreatmentOptions

A. New Source Performance StandardsThe basis for new source performance

standards under Section 306 of the Actis the 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 themaximum extent feasible.

The Agency has investigated severalcontrol and treatment options as a basisfor NSPS to reduce the discharge ofpollutants in waste streams generatedby the offshore segment of this industry.These options and the rationale forselecting NSPS are presented below forthe major waste streams.

1. Produced Water(a) Control and Treatment Options

Considered. EPA evaluated thefollowing three control and treatmentoptions for establishing NSPS forproduced water.

OPTION 1

Option 1 would base performancestandards on the improved performanceof BPT technology. A discharge standardof 59 mg/I (maximum) for oil and greasewould result from this option. For the833 projected new source platforms inthe year 2000, this level of technologywould result in an annual reduction of700,000 pounds of oil and grease beyondthe allowable BPT discharge level. Thisoption would not result in quantifiablereductions of priority pollutants beyond

those achieved by existing BPT-typetreatment technologies.

The Agency was unable to developincremental cost estimates for imposingOption 1 on all new source platforms.This is because the elements ofimproved operation and maintenance ofBPT treatment equipment are very sitespecific. However, the Agency doesbelieve that; for any particular newsource platform, such costs are minimalcompared to the installed costs of theBPT equipment and the cost of operationand maintenance to achieve the BPTeffluent limitations. Also, new sourceoperators have the opportunity to designfor and install the latest equipment asan integrated part of the platformsuperstructure; therefore they would notbe subject to any retrofit expendituresthat were incurred by existing platformsto comply with the BPT regulations.Furthermore, the Offshore Operator'sCommittee report titled Potential Impactof Proposed EPA BA T/NSPS Standardsfor Produced Water Discharge FromOffshore Oil and Gas ExtractionIndustry (January 1984), projects that atleast 75 percent of the existing offshoreplatforms in the Gulf of Mexico arealready achieving the 59 mg/I oil andgrease limitation with treatmenttechnology designed to achievecompliance with BPT limitations.

OPTION 2

Option 2 would base performancestandards on granular media filtrationas an add-on technology to BPT. Thislevel of technology would result inadditional reductions of conventionalpollutants beyond the BPT level ofcontrol. Effluent limitations of 20 mg/Imonthly average and 30 mg/I dailymaximum for both oil and grease andtotal suspended solids would result fromthis option. For the 833 projected newsource platforms, this option wouldresult in an annualized cost of $275.7million in the year 2000 (1983 dollars).Investment costs for the 62 platformsexpected to be installed in the year 2000are estimated to be $185.4 million (1983dollars). These compliance costs areincremental to BPT technology, i.e., theydo not include the costs for BPTtechnology.

This option would result in an annualreduction of 4.2 million pounds of oiland grease beyond the levels allowedunder the BPT level of control.Significant reductions of totalsuspejnded solids levels are alsoachieved by granular media filtration.No quantifiable reductions in prioritypollutants found in BPT-treateddischarges would be achieved by thisoption'.

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OPTION 3

Option 3 would require zerodischarge, based upon reinjectiontechnology. This level of technologywould result in no discharge ofpollutants to surface waters.

For the projected 833 new platforms,this option would result in anannualized cost of $487.1 million in theyear 2000 (1983 dollars). Investmentcosts for the 62 platforms expected to beinstalled in the year 2000 are estimatedto be $442.0 million (1983 dollars). Thesecompliance costs are incremental to BPTtechnology, which may be requiredahead of the reinjection system requiredby this option.

This option would result in an annualreduction of 3.9 million pounds ofpriority pollutants beyond the dischargelevels observed for existing platformsusing BPT technology. This option wouldalso result in an annual reduction of 7.0million pounds of conventionalpollutants (oil and grease) beyond thelevels allowed under the BPT level ofcontrol. Significant reductions of totalsuspended solids levels are alsoachieved by this option.

(b) Selected Option and Basis forSelection. The option which the Agencyis proposing for NSPS is a combinationof Options 1 and 3. Option 3, or zerodischarge, would be required for all oilproduction facilities that are located inor would discharge to shallow waterareas, i.e., platforms in 20 meters ofwater or less in the Gulf of Mexico, theAtlantic Coast, and the Norton Basin; in50 meters of water or less for theCalifornia Coast, Cook Inlet/ShelikofStrait, Bristol Bay, and Gulf of Alaska;and in 10 meters of water or less in theBeaufort Sea. The regulatory boundariesfor each of these areas are defined inAppendix 4 of today's proposedregulation. The Agency has selectedOption 1, improved BPT-treatmentt'chnology, which requires compliancewith a 59 mg/l limitation for oil andgrease (maximum for any singlesample), for all oil facilities that areneither located in nor discharge to theseshallow water areas, for all gas facilitiesregardless of location or water depth,and for all exploratory facilitiesregardless of location or water depth.

This selected option would require anestimated 13Z new oil productionfacilities to meet the zero dischargestandard. The other 701 new productionfacilities would be required to meet anoil and grease standard of 59 mg/l(maximum) based upon improvedperformance of BPT technology.

In selecting NSPS for produced water,the Agency considered the technicalfeasibility and industry conipliance

costs of imposing each of the abovethree NSPS options. In addition. EPAcalculated aggregate industrycompliance costs with variouscombinations of these options basedupon platform type and location. Therecord supporting today's proposalpresents the details of these otheroptions.

Because Option 3, which is based onreinjection, is the only treatmenttechnology that EPA found to be bothtechnologically feasible to implementand capable of achieving reductions ofall pollutants, including prioritypollutants, the Agency focused itsevaluation on reinjection. The Agencyrecognized that, while reinjection is anavailable and demonstrated technologyfor controlling the discharge ofpollutants in produced water fromoffshore oil and gas facilities, theAgency also had to consider the costs ofimplementing such a control option. Theestimated total annualized cost for all833 projected new facilities toimplement reinjection of produced wateris $487.1 million in the year 2000 (1983dollars). In light of the statutorymandate to consider cost in establishingNSPS, EPA decided to reject theimposition of this option on all newfacilities in the offshore subcategorybecause of its very high aggregate cost.This prompted the Agency to evaluatelimiting the scope of a zero dischargerequirement (i.e., reinjection) in order toreduce the total cost.

To analyze possible ways to reducethe total aggregate cost of Option 3, theAgency then developed costs forreinjection based upon the type offacility, i.e., oil platforms or gasplatforms. Not imposing a zerodischarge requirement on the estimated537 new source gas platforms wouldreduce the annualized cost of NSPSOptioin 3 by $217.8 million. in the year2000 (1983 dollars). The Agency decidedto exclude all gas platforms fromcoverage by Option 3 to reduce totalaggregate costs.

To confirm this decision, EPAevaluated the characteristics ofproduced water from oil platformsversus gas platforms. The Agencydetermined that, while produced waterfrom gas wells exhibits higherconcentrations of the priority pollutantsthen produced water from oil wells(approximately fourfold higher), thetypical flow volume of produced waterfrom gas wells is significantly less(approximately 1/15) than that for oilwells. Thus, on a mass basis, dischargesof priority pollutants from gas wells areapproximately 25 percent of those fromoil wells. The higher quantity of prioritypollutants discharged from oil platforms

compared to gas platforms supports theAgency's decision that deleting gasplatforms from a zero dischargerequirement to reduce aggregateannualized costs was appropriate. Thisreduced total annualized costs to $269.3million (1983 dollars) while continuing totarget attention on the discharges ofgreatest concern.

While total projected annualized costswere reduced, the Agency believed that$269.3 million was still too high andevaluated reducing costs further bylimiting the zero discharge option toshallower waters where compliancecosts would be less. Facilities in shallowwaters generally have the alternative ofonshore reinjection which is less costlythan reinjection offshore.

The Agency has found that inshallower waters a high percentage ofthe existing production platforms pipe toshore for treatment rather than treatingthe produced waters on the platform.The Agency has also determined thatthe costs of drilling and equippingreinjection wells on land is less costlythan drilling reinjection wells at theplatform.

The Agency has selected variabledepth limits for different offshore areaswhich represent the shallower watersand which generally allow for thealternative of onshore reinjection by thefacility.

Industry data for the Gulf of Mexicoindicate that 82 percent of the projectednew sources in state waters and 25percent of the projected new sources infederal waters would pipe producedwater to shore for treatment. The dataalso indicate that about 52 percent of allnew sources in 15 meters or less ofoffshore waters would pipe producedwater to shore. The Agency believes thissame percentage of platforms in waterdepths of 20 meters or less could pipe toshore and reinject.

The 20 meter water depth was alsoselected for the Atlantic Coast. There isno historic trend for productionplatforms in this area. Therefore, theGulf of Mexico statistics on the probablepractice of onshore reinjection wereassumed to be applicable for productionfacilities in the Atlantic Ocean.

In California, statistics indicate that60 percent of the active productionplatforms located in water depths of 50meters or less pipe to shore fortreatment and only eight percent of thefacilities in water depths greater than 50meters pipe to shore for treatment.Based on this data, a depth of 50 metersor less was selected for the CaliforniaCoast.

The Agency does not have historicdata on production platforms for some

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parts of Alaska since no offshoreproduction platforms have beenconstructed to date in those areas. All ofthe 14 existing production platforms inCook Inlet are classified in the coastalsubcategory. The Agency believes thatthe Southern Alaskan bathymetry issomewhat similar to California'sbathymetry and therefore, a water depthof 50 meters or less is proposed forSouthern Alaska since platformslocating in this water depth may chooseto pipe produced water to shore fortreatment, The Southern Alaska regionincludes the Bristol Bay/Aleutian IslandChain, Cook Inlet and the Gulf ofAlaska. The Agency realizes that someof these areas may not be amenable topiping to shore for reinjection becauseof seasonal ice formations, glaciers, orunsuitable terrain. However, the Agencybelieves that piping to shore in shallowwaters will occur in areas that aresuitable.

For other parts of Alaska, the Agencybelieves the platforms which locate inthe Norton Basin in water depths of 20meters or less and in the Beaufort Sea in10 meters or less will have the option ofpiping to shore for treatment. The waterdepths are less than the 50 metersselected for Southern Alaska becausethe harsher climates in these morenorthern regions would result in a lesserprobability of piping to shore fortreatment.

The Agency developed a zerodischarge option for facilities in 20 metersof water or less in the Gulf of Mexico,the Atlantic Coast and the Norton Basin;for 50 meters of water or less for theCalifornia Coast and Southern Alaskaincluding the Aleutian Island Chain; andfor 10 meters of water or less in theBeaufort Sea.

EPA then calculated the total costs ofthis zero discharge option in shallowerwaters. In the Gulf of Mexico, theagency projects that 124 new platformswill be built in 20 meters of water or lessby the year 2000. The Agency estimatesannualized costs of a zero dischargestandard to be $50.0 million in the year2000 (1983 dollars). For the CaliforniaCoast, the Agency projects two newplatforms that will be built in 50 metersor less of water and estimates theannualized cost to be $5.5 million (1983dollars). While six platforms are -projected to be built in the shallowwaters of the Beaufort Sea, the Agencyis not attributing incrementalcompliance costs to this regulationbecause existing Department of theInterior and State of Alaska leasestipulations already require zerodischarge of produced water. However,these costs are included in the Agency's

baseline economic analysis for theseproposed regulations. Similarly, no costsare attributed to Atlantic Coastoperations because no facilities areprojected to be built in 20 meters ofwater or less by the year 2000.Nonetheless, EPA realizes thatdevelopment is possible in the Atlanticand has found that reinjectiontechnology is feasible for meeting a zerodischarge standard for platforms locatedin 20 meters of water or less for theAtlantic Coast.

The proposed regulatory option,developed from the variable depthconsiderations presented above, resultsin an annualized cost of $55.6 million inthe year 2000 (1983 dollars). Theannualized costs apply to 126 of the 132new oil facilities expected to be builtbetween 1986 and the year 2000 whichwould be subject to this zero dischargerequirement. The other six facilities areprojected to be located in Alaskanwaters and subject to reinjection, butthe cost of reinjection is not attributedto this regulation, as described above.The Agency found these costs to beeconomically achievable. This costrepresents the total annualized cost ofNSPS. This is because the Agency'sselection of improved BPT performance(i.e., 59 mg/I maximum oil and grease)for all facilities not subject to the zerodischarge standard would result innegligible costs incremental to BPT.

As explained above, the agencyassumes only minimal incremental costsfor new sources to meet 59 mg/l oil andgrease for produced water. The Agencyselected Option 1 (improved BPT) overoption 2 (filtration) because theaggregate annualized cost of $275.7million (1983 dollars) to implementOption 2 is believed to be too high.

The proposed regulatory option wouldresult in an estimated annual reductionof 700,000 pounds of priority pollutantsbased on discharge levels observed forexisting facilities using BPT technology.This option would also result in anannual reduction of 1.3 million poundsof conventional pollutants beyond thedischarge levels allowed under the BPTlevel of control. No decline in energyproduction is projected to occur fromthis option.

Both reinjection and improved BPTtechnology represent the application ofthe best available demonstrated controltechnology in the respective areaswhere they will need to be used to meetthe proposed standards. The Agency hasthoroughly considered the cost ofachieving the proposed standards andconcludes that the costs will not be abarrier to future entry into offshore oiland gas exploration, development or

production operations. No adverse non-water quality environmental impacts orsubstantial increases in energyrequirements will occur as a result ofthese proposed regulations.

This proposed option would requireproduced water from all newexploration facilities regardless oflocation or water depth to comply with a59 mg/i maximum oil and greasestandard, based upon improvedoperation of BPT. Because of the shortduration of exploratory operations, thesmall amount of water which isgenerated during exploratoryoperations, and the fact that eachexploratory well could require thedrilling of a reinjection well, the Agencyconcluded that the cost of a zerodischarge requirement for anyexploratory operation is too high.

EPA is proposing that development/production facilities that would have toimplement zero discharge under thisoption would have up to 300 days fromthe commencement of well drillingoperations to begin complying with thezero discharge standard. For thispurpose, commencement of well drillingoperations means the start of boreholedrilling for the first development well atan offshore oil facility.

During this 300-day period, anydischarges of produced water wouldhave to comply with a 59 mg/l(maximum) oil and grease standard,which is based upon improvedperformance of BPT technology. This300-day period is being proposed inorder to allow for the use of any dry(non-producing) wells which aresuitable for reinjection. It is based uponthe time required for the averagenumber of development wells to bedrilled before encountering a dry wellthat could be reworked and equipped foruse as an injection well, and the averagetime to rework and equip the dry wellfor injection of produced water.-If no drywells become available and are readyfor use as injection wells within thisperiod, then compliance with the zerodischarge standard would be achievedby drilling and equipping an injectionwell(s) for use by the 301st day from thecommencement of development drillingoperations.

The Agency estimates that, typically,less than two percent by volume of theproduced water generated over the lifeof a facility would be discharged duringthe initial 300-day period. The Agencyestimates that the difference in costbetween the use of a new injection welland use of a reworked dry well forreinjection is a minimum of $400,000 perfacility. The Agency believes that it isreasonable to delay the requirement for

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meeting zero discharge by new offshoreoil facilties for 300 days fromcommencement of develoment drilling inorder to minimize the expenditure ofthese substantial costs.

The reasonableness of the Agency'sdecision to require zero discharge in theshallow waters is confirmed by theAgency's analyses which show that itwould provide protection to the mostenvironmentally sensitive marineenvironments. In reviewing theenvironmental documents referenced inSection VIID, the Agency determinedthat the highest probability of directenvironmental effects of produced waterdischarges is most prevalent inshallower waters. In the Gulf of Mexico,for example, species distribution dataprovided by the National Oceanic andAtmospheric Administration (NOAA)indicate that water depths of 20 metersor less encompass approximately 88percent of the nursery areas for selectedfish and invertebrates. The Agencyprojected that 124 new platforms wouldbe built in 20 meters or less of water inthe Gulf of Mexico.

The Agency also evaluated theBeaufort Sea, Norton Basin, Cook Inlet,Bristol Bay, and the Gulf of Alaska inAlaska. EPA analyses indicate that a 10-meter isobath (i.e., water depth of 10meters or less) in the Beaufort Sea; a 20-meter isobath in the Norton Basin; and a50-meter isobath in Cook Inlet/ShelikofStrait, Bristol Bay, and the Gulf ofAlaska would provide substantialprotection of valuable life stages for thecommercial and subsistence species ineach region.

For the California Coast, EPA'sanalyses indicate that.the 50-meterisobath will protect the majority of thedesignated areas of biologicalsignificance. It will also protect most ofthe known nursery areas.

Along the Atlantic Coast, speciesdistribution data were obtained fromNOAA that indicate approximately 83percent of the nursery areas for theselected fish and invertebrates areencompassed by water depths of 20meters or less.

A zero discharge requirement forproduced water would also achievecontrol of many nonconventional, toxicpollutants in addition to the 126 listedpriority pollutants (See Appendix C ofthis preamble). An EPA survey of 10production platforms in Louisiana (the"Crest" report) identified chemicalscontaining toxic or nonconventional,toxic pollutants in use on the platformsthat were either present or likely to bepresent in produced water. Thesechemicals include biocides, coagulants,corrosion inhibitors, cleaners,dispersants, emulsion breakers, paraffin

control agents, reverse emulsionbreakers, and scale inhibitors.Detergents used to clean the platformswere also found in produced water. TheAgency is currently collecting additionalinformation on the use and effects ofbiocides and other chemicals in thisindustry for consideration indevelopment of the final regulations.

The regulatory boundaries for eachgeographic area covered by today'sproposed regulations are based on someof the Minerals Management Service(MM9) proposed planning areas for thenew 5-year Outer Continential Shelf(OCS) oil and gas leasing program (49FR 28332, July 11, 1984) whichencompass all federal oil and gas leaseactivities. For the purpose of today'sproposed regulations, the regulatoryboundaries include the area from thestate water boundary that adjoins theMMS planning area boundary landwardto the inner boundary of the territorialseas. In addition, the outer (seaward)boundary of each regulatory area isproposed to coincide with the 200-mileFishery Conservation Zone boundary.

The regulatory areas include the Gulfof Mexico, the Atlantic Coast, theCalifornia Coast and portions ofAlaskan waters, as presented inAppendix 4 of today's proposedregulations.

2. Drilling Fluids

(a) Control and Treatment OptionsConsidered. This section presents theregulatory options considered for NSPSdrilling fluids. Because these options arethe same as the options considered forBAT, the discussion of costs ispresented in the BAT section for drillingfluids. Thus there are no NSPS costs orimpact incremental to BAT for drillingfluids.

OPTION 1-TOXICITY LIMITATION

This option would result in theregulation of free oil, oil-based fluids,diesel oil, cadmium, mercury and thetoxicity of the discharged drilling fluid.Most of these limitations are achievedby product substitution-specifically,through the use of water-based drillingfluids (i.e., generic muds), low toxicityspecialty additives, the use of mineraloil instead of diesel oil for lubricity andspotting purposes, and use of barite withlow toxic metals content.

Under this option the discharge of freeoil would be prohibited, as in theexisting BPT regulation. The dischargeof oil-based fluids would also beprohibited. Oil-based fluids typicallycontain 50 or more volume percent of oil.One method of compliance issubstitution with less toxic water-basedfluids. Water-based, or generic, drilling

fluids, as explained under Option 2below, can be used in virtually alloffshore drilling situations. '

The prohibition on the discharge offree oil for BPT effectively prohibits thedischarge of oil-based drilling fluids.Therefore, any differential costsincurred to implement substitution ofwater-based for oil-based fluids is a costattributable to compliance with BPTrequirements. Moreover, in contrast tothe BPT regulation, this NSPS optioncontains an explicit prohibition on thedischarge of oil-based fluids in additionto the prohibition on discharges of freeoil. The alternative to productsubstitution, i.e., use of water basedmud systems, is to transport the spentmud system to shore for reconditioning,recovery or land disposal.

The prohibition on the discharge ofoil-based fluids is included in this optionas an "indicator" of the toxic pollutantspresent in oil-based fluids. The free oildischarge prohibition in BPT originallywas imposed to prevent the discharge ofoils in amounts that would cause asheen on receiving waters and thislimitation will continue.

The discharge of diesel oil, either as acomponent in an oil-based drilling fluidor as an additive to a water-baseddrilling fluid, would, be prohibited underthis option. Diesel oil would beregulated as a toxic pollutant because itcontains such toxic organic pollutants asbenzene, toluene, ethylbenzene,naphthalene, and phenanthrene. Themethod of compliance with thisprohibition is to use mineral oil insteadof diesel oil for lubricity and spottingpurposes. Mineral oil is a less toxicalternative to diesel oil and is availableto serve the same operationalrequirements. Low toxicity mineral oilsare also available as substitutes fordiesel oil and continue to be developedfor use in drilling fluids.

The purpose of the toxicity limitationfor any drilling fluids which are to bedischarged is to encourage the use ofgeneric or water-based drilling fluidsand the use of low-toxicity drilling fluidadditives (i.e., product substitution). 'hebasis for the toxicity (LC-50] limitaionis the toxicity of the most toxic of thegeneric fluids discussed in Option 2below. The most toxic generic fluid ispotassium/polymer mud (see AppendixB of this preamble). The imposition of anLC-50 toxicity limitation for all drillingfluids which are to be discharged wouldallow for use of at least any of the eightgeneric drilling fluids. Seven of thegeneric drilling fluids (i.e., all butpotassium/polymer mud) could besupplemented with low-toxicityspecialty additives and lubricity agents

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to meet operational requirements, andshould still be able to comply with theLC-50 toxicity limitation prior todischarge. The potassium/polymerdrilling fluid probably could not besupplemented with additives thatexhibit a toxicity greater than theproposed LC-50 limitation because theLC-50 toxicity limitation is based uponthe base formulation of this drillingfluid. However, industry operators anddrilling fluid suppliers have indicatedthat potassium/polymer drilling fluid isseldom used. In drilling situations wherethere is no substitute for potassium/polymer drilling fluid for operationalreasons, such a spent mud system wouldcomply with the proposed LC-50 toxicitylimitation (3 percent, diluted suspendedparticulate phase) only if any requiredlubricity agents (oils) or specialtyadditives are no more toxic than thebase mud formulation. Such additivesare available. However, where thetoxicity of the spent mud systemexceeds the LC-50 toxicity limitation,the method of compliance with thisoption would be to transport the spentfluid system to shore for eitherreconditioning for reuse or landdisposal.

The toxicity limitation would apply toany periodic blowdown of drilling fluidas well as to bulk discharges of drillingfluid systems. The term drilling fluidsystems refers to the major types ofmuds used during the drilling of a singlewell. As an example, the drilling of aparticular well may use a spud mud forthe first 200 feet, a seawater gel mud toa depth of 1,000 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 1,000to 2,000 barrels of spent drilling fluidsoccur when such mud systems arechanged during the drilling of a well orat the completion of a well.

For the purpose of self monitoring andreporting requirements in NPDESpfermits, 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 at

any time after 80 percent of actual wellfootage (not total vertical depth) hasbeen 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, oil-based drilling fluids, and diesel oilwould apply to all discharges of drillingfluid at any time.

Cadmium and mercury would beregulated at a level of 1 mg/kg, each, asa maximum value ("not to exceed") on adry weight basis in any spent drillingfluid system discharge. These two toxicmetals would be regulated to control themetals content of the barite componentof any drilling fluid discharges. Themethod of compliance with theselimitations is product substitution. Thisinvolves use of barite from sources thateither do not contain these metals orcontain the metals at low enough levelssuch that resultant levels in dischargesof the drilling fluid do not exceed thelimitations.

The causes for noncompliance withthe specific requirements of this optioncould include: inability to use a drillingfluid that can meet the proposed toxicitylimitation, such as the need for an oil-based mud or a potassium/polymer mudwith oil additives because of operationalreasons, the need to add lubricity agentsor other specialty additives to a mudsystem to meet particular operationalrequirements, or the unavailability ofbarite containing low toxic metalslevels. However, as previously noted,BPT effectively prohibits the dischargeof oil-based drilling fluids, and less toxicwater-based fluids are availablesubstitutes. Although the potassium/polymer mud represents the most toxicwater-based fluid allowed for discharge,it is seldom used for offshore drillingpurposes. It is also recognized that theavailability of barite stocks containinglow levels of trace metals could belimited at any given time due to marketconditions. For the purposes of today'sproposal, the Agency assumed that

sufficient sources of such barite do existand can be directed to offshore drillinguse in those cases where an operatorintends to discharge drilling fluids.Mineral oil is an available alternative todiesel oil for use as a lubricant orspotting fluid. Although there arespecialty additives for which less toxicsubstitutes have not been identified, thetoxicity limitation is applied to the'discharge of the entire drilling fluidsystem, and not to individualcomponents. Thus, the Agency believesthat only a limited number of offshoredrilling operations would not be allowedto discharge spent drilling fluids due toviolation of one or more of therequirements of this option. Aconservative estimate is that, at most,ten percent of all 9pent drilling fluidsystems would violate the proposedlimitations and would have to betransported to shore to comply with thisNSPS option.

OPTION 2-CLEARINGHOUSEAPPROACH

Option 2 would provide for theestablishment of a nationalclearinghouse administered by EPAwhich would serve as a repository forall toxicity and related physical andchemical characteristics of base drillingfluid formulations and additives. Thisinformation would be available tooperators (as well as the general public)for use in selecting drilling fluidformulations that would likely complywith the established toxicity limitation.The initial list would include the eightgeneric fluids discussed in Section VIIIand presented in Appendix B of thispreamble. These fluids are of knowncomposition and toxicity and have beenevaluated and listed as acceptable fordischarge in NPDES permit actions.

Chemical and toxicity information onnew additives and mud formulationswould be included in the clearinghousedata base as adequate testing databecome available.

OPTION 3-ZERO DISCHARGE

This option would require zerodischarge for all drilling fluids, basedupon transport of spent drilling fluids toshore for recovery, reconditioning forreuse, or land disposal, or transport toan approved ocean disposal site. Thislevel of technology would result in nodischarge of pollutants to surface watersexcept at approved ocean disposal sites.

(b) Selected Option and Basis forSelection. EPA has selected Option I asthe basis for proposed new sourceperformance standards for drillingfluids. The proposed standards includethe following limitations:

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e A prohibition on the discharge offree oil, oil-based drilling fluids, anddiesel oil, all considered as "indicators"of priority pollutants.

e A 96-hour LC-50 toxicity limitationon the discharged drilling fluids of noless than 3.0 percent by volume of thediluted suspended particulate phase.

• A maximum limitation (i.e., nosingle sample to exceed) on the amountof cadmium and mercury in dischargeddrilling fluids of I mg/kg each.

The prohibitions on the discharge offree oil, oil-based drilling fluids, anddiesel oil are all intended to limit the oilcontent in drilling fluid waste streamsand thereby control the priority as wellas conventional and nonconventionalpollutants present in those oils. Thepollutants "free oil," "oil-based drillingfluids," and "diesel oil" are eachconsidered to be "indicators" of thepriority pollutants present in thesecomplex hydrocarbon mixtures used indrilling fluid systems. These pollutantsinclude benzene, toluene, ethylbenzene,napthalene and phenanthrene. TheAgency's primary concern is controllingthe priority pollutants in the oilsalthough these prohibitions also willserve to control nonconventional andconventional pollutants. The Agencyselected the "indicator" approach as analternative to establishing limitations oneach of the specific toxic and nontoxicpollutants present in these oil-contaminated wastestreams. Thesampling and analysis data demonstratethat when the amount of oil, especiallydiesel, is reduced in drilling fluid, theconcentrations of priority pollutants andthe overall toxicity of the fluid generallyare reduced. The Agency hasdetermined that control of the amount ortype of oil present in drilling fluids withlimitations on the three "indicators"(free oil, oil-based drilling fluids anddiesel oil) will provide a good level ofcontrol of the priority pollutants presentin drilling fluids. This method of toxicregulation obviates the difficulties andcosts of monitoring and analysis iflimitations were established for each ofthe organic priority pollutants present inthe drilling fluids. The Agency requestscomment on its decision to use thesethree limitations as "indicators" ofpriority pollutants. The Agency alsorequests comment on whetherlimitations should be established foreach of the specific organic prioritypollutants present in drilling fluids.

The purpose for the LC-50 toxicitylimitation on the discharge of drillingfluids is to reduce the toxic contituentsin drilling fluid discharges. While thethree indicator limitations on theamount or type of oil present in drillingfluids should significantly reduce the

toxic pollutants present in drilling fluids,other additives such as mineral oil orsome of the numerous specialtyadditives may greatly increase thetoxicity of the drilling fluid. The toxicityis, in part, caused by the presence. andconcentration of priority pollutants. Byestablishing a toxicity limitation, theAgency believes that operators willconsider toxicity in s6lecting additivesand select the less toxic alternative. Forinstance, there can be a broad spectrumin the toxicity of mineral oils. TheAgency believes that the Clean WaterAct authorizes the Agency to establish atoxicity limitation as an effluentlimitation designed to control thechemical or toxic constituents of thedischarge. The availability of a wideselection of additives makes product'substitution the best availabledemonstrated technology for complyingwith the toxicity limitation. The Agencyhas considered the costs of productsubstitution and finds them to beacceptable for this industry, resulting inno barrier to future entry. Thesestandards are not expected to have anyadverse non-water qualityenvironmental impacts or increaseenergy requirements. The genericdrilling fluids list is a primary basis forboth the prohibitions on the discharge offree oil and oil-based drilling fluids andthe LC-50 limitation. As discussed insection VIII; EPA has determined,through the NPDES permit process, thatthe eight generic water-based drillingfluids, Whose formulations are presentedin Appendix B of this preamble, areadequate for virtually all drillingsituations and are less toxic than oil-based drilling fluids. In order for adrilling fluid to be discharged, it must beno more toxic than the proposed LC-50standard as determined with the DrillingFluids Toxicity Test presented inAppendix 3 of today's proposedregulation.

Under this option, a drilling fluid canbe discharged only if it does not containadditives that would cause its toxicity toexceed the toxicity of the most toxicgeneric mud. Further, EPA hasdetermined that refined mineral oil is anadequate substitute for diesel oil and isa less toxic alternative to diesel oil.Accordingly, diesel oil would not be anallowable additive, either as a lubricityagent or spotting fluid, to a drilling fluidintended to be discharged. Mineral oilwould be allowed as a lubricity agentand spotting agent in the drilling fluidprovided that its addition would notcause the toxicity of the dischargeddrilling fluid, including all otheradditives, to exceed the proposed LC-50standard.

The limitations on cadmium andmercury for discharged drilling fluidsare intended to control theconcentrations of toxic metals in barite,a major component of drilling fluids. Asdiscussed above, these limitationswould be met by product substitution,the best available demonstratedtechnology which is economicallyachievable.

In addition, the Agency is proposing adifferent definition of the term "nodischarge of free oil" from thatpromulgated for the BPT regulation (44FR 22075, April 13, 1979). Also, the testprocedure for determining compliancewith this prohibition on free oildischarges is proposed to be changedfrom that used for BPT. This revised testprocedure is called the "Static SheenTest", and is presented in Appendix I oftoday's proposed regulation. Therationale for these proposed changes isthe same as that discussed in SectionXI.B.

This NSPS option is the same as theproposed BAT option for drilling fluids,as discussed below. Therefore, there areno NSPS compliance costs or impactsincremental to BAT for drilling fluids.

Option 2 was not selected as the basisfor NSPS at this time because theAgency does not anticipate such a"clearinghouse" program to beestablished prior to promulgation ofNSPS. Development of listingmethodologies and criteria andcompilation of an adequate toxicity database, which is central to the"clearinghouse approach" of Option 2, isestimated to take from three to fiveyears. Such methodologies, criteria anddata are essential for fullimplementation on a nationwide basis.The Agency has begun to investigate therequirements for management of aclearinghouse approach. Uponcompletion of the investigation and ifthe Agency establishes such a program,the Agency may decide to propose toamend the approach to NSPSaccordingly.

The Agency rejected Option 3, zerodischarge, for implementation on anational basis for two major reasons.The Agency believes that the aggregateindustry compliance costs of $126.3million annually (1983 dollars) fortransport and land disposal of all spentdrilling fluids is too high. In addition, theAgency believes that there may beproblems with adequate landavailability for disposal of spent drillingfluids under such a zero dischargeoption. In part, this may be due toexisting or future restrictions on the landdisposal of drilling fluids under the

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Federal Register I Vol. 50, No. 165 / Monday, August 26, 1985 / Proposed Rules

requirements of hazardous wastedisposal laws.

3. Drill Cuttings

(a) Control and Treatment OptionsConsidered. Option I would result in theregulation of free oil, oil-based fluids,and diesel oil in discharged drillcuttings. These limitations, as for theselected option for drilling fluids, areachieved by product substitution.Water-based drilling fluids would besubstituted for oil-based fluids andmineral oil would be substituted fordiesel oil. These three pollutantparameters would be regulated in amanner identical to that for the samepollutant parameters for drilling fluidsOption 1. The rationale for theirregulation is also the same as for drillingfluids Option 1 because the constituentof concern in the drill cuttings wastestream is the residual drilling fluid thatadheres to the drill cuttings.

Option 2 would be equivalent toOption I plus a limitation on theallowable oil content of the dischargedcuttings. The oil content limitation of 10percent maximum by weight would bebased upon water/detergent washertechnology, as discussed in Section X ofthis preamble. This "residual oil"limitation would be imposed as anindicator of toxic pollutants, specificallythe priority organic pollutants in oilsthat are added to drilling fluid systems,and to control conventional pollutants inthis waste stream.

Option 3 would require zero dischargeof all drill cuttings, based upon transportof drill cuttings to shore for landdisposal or to an approved oceandisposal site. This option would result inno discharge of pollutants to surfacewaters except at approved oceandisposal sites.

(b) Selected Option and Basis forSelection. The Agency selected Option 1as the basis for proposed NSPS for drillcuttings. The requirements of Option Iare comparable to those of the selectedoption for drilling fluids.

The Agency did not select Option 2 atthis time because it believes thatestablishing an oil content limitation ondrill cuttings may be redundant becausethe prohibition on the discharge of freeoil appears to be a more stringentlimitation. While presentlydemonstrated cuttings washertechnology will reduce residual oilcontent to less than ten percent byweight, the Agency's data base indicatesthat visible sheen can be caused by aslittle as one percent oil. Thus, the freeoil discharge prohibition may be morestringent than any residual oil limitationthat can be presently established withcuttings washer technology that has

been demonstrated on a full-scale basis.The Agency will collect and evaluateadditional cuttings washer performancedata, especially with respect to the useof mineral oil for lubricity and spottingpurposes, to establish whether an oilcontent limitation is more stringent thanthe prohibition on the discharge of freeoil.

The Agency rejected Option 3, zerodischarge, because of high aggregatecompliance costs and land availabilityproblems as discussed below for drillingfluids BAT Option 3.

4. Deck Drainage

As with BAT/BCT, the Agency isproposing to establish NSPS for deckdrainage the same as the BPT level ofcontrol. This would result in aprohibition on the discharge of free oil.The technology basis is oil-waterseparation. The Agency is reservingcoverage for all other pollutantparameters and characteristics for deckdrainage pending additional datacollection and analysis. This additionaldata will include toxic,nonconventional, and conventionalpollutant information and control andtreatment technology evaluation.

The method of determiningcompliance with the free oil prohibitionis by the static sheen test discussedearlier and as presented in Appendix Iof today's proposed regulation. Wheredeck drainage is collected and treatedseparately from produced water, the freeoil pl'ohibition would apply. However,where deck drainage is commingled andcotreated with produced water, only theeffluent limitations for produced waterwould apply to these two combinedwaste streams.

Because this proposed standard isequal to BAT/BCT, there are noincremental compliance costs due toNSPS.

5. Sanitary Wastes

The Agency is proposing to establishNSPS for sanitary wastes equal to theBAT/BCT level of control. This wouldresult in: (1) a prohibition on thedischarge of floating solids for facilitiesmanned by nine or fewer persons orintermittently manned by any number ofpersons; and (2) an effluent standard forresidual chlorine of 1 mg/i minimum andto be maintained as close as possible to1 mg/l, for facilities continuouslymanned by ten or more persons.Because these proposed standards areequal to BAT/BCT, there are noincremental compliance costs due toNSPS,

6. Domestic Wastes

The Agency is proposing to establishNSPS equal to the BCT level of controlfor domestic wastes. This would resultin a prohibition on the discharge offloating solids. Since NSPS would equalBCT, no compliance costs incremental toBCT are associated with this standard.

7. Produced Sand

As with BAT/BCT, the Agency isproposing to establish a prohibition onthe discharge of free oil for producedsand NSPS. The technology basis forthis standard is water or solvent washof produced sands prior to discharge, ortransport of produced sand to shore forland disposal. The method ofdetermining compliance with the free oilprohibition is by the static sheen testdiscussed earlier and as presented inAppendix 1 of today's proposedregulation. There are no NSPScompliance costs incremental to theproposed BAT/BCT limitations.

The Agency is reserving coverage forall other pollutant parameters andcharacteristics for produced sandpending additional data collection andanalysis. This additional data willinclude toxic, nonconventional, andconventional pollutant information andcontrol and treatment technologyevaluation.

8. Well Treatment Fluids

The Agency is proposing to establishan NSPS prohibition on the discharge offree oil for well treatment fluids as an"indicator" to reduce or eliminate thedischarge of any toxic pollutants in thefree oil to surface waters. The method ofdetermining compliance with the free oilprohibition is by the static sheen testdiscussed earlier and as presented inAppendix I of today's proposedregulation. This is equal to the proposedBAT level of control, as discussedbelow. Therefore, there are no NSPScompliance costs incremental to BAT.

The Agency is reserving NSPScoverage of all other pollutantparameters for well treatment fluids andcharacteristics pending additional datacollection and evaluation. Thisadditional data will include toxic,nonconventional and conventionalpollutant information and control andtreatment technology evaluation.

B. Best Available Technology

1. Produced Water

The Agency is not proposing BATeffluent limitations for produced waterfrom existing sources at this time. TheAgency lacks sufficient information onreinjection and control of biocides and

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other chemical usage by existingfacilities to properly evaluate thetechnological feasibility and economicachievability of these options.

The Agency is presently undertaking adata collection effort to obtain industryprofile information, retrofit costinginformation for reinjection, informationon the extent of biocide and otherchemical use, and associatedenvironmental impacts for existingfacilities. Upon analysis of thisinformation, the Agency may propose ata future date a BAT regulatory option of:(1) reinjection based upon water depthor use of biocides and other chemicals;(2) product substitution to .require theuse of less toxic or persistent biocidesand chemicals; (3) establishment ofeffluent limitations to limit thequantities of biocides and chemicalsdischarged or an option based upon acombination of these three approaches.

Because BAT is intended to controltoxic and nonconventional pollutants,the Agency will not further consider theimproved BPT or filtration technologiesof options 1 and 2 for existing sourcesbecause these technologies primarilycontrol conventional pollutants, and donot effect quantifiable reductions oftoxic pollutants.

2. Drilling Fluids

(a) Control and Treatment OptionsConsidered.

OPTION 1-TOXICITY LIMITATIONAPPROACH

This option is the same as NSPSOption I for drilling fluids. It wouldregulate the discharge of free oil, oil-basetl fluids, diesel oil, cadmium,mercury and the toxicity of dischargeddrilling fluids. These limitations areachieved by product substitutionthrough the use of water-based drillingfluids (i.e., generic muds), low toxicityspecialty additives, the use of mineraloil instead of diesel oil for lubricity andspotting purposes, and use of barite withlow toxic metals content. The purposeand rationale for these effluentstandards is the same as that presentedabove for NSPS.

This option would result in an annualcost of $26.3 million (1983 dollars) for anestimated 1166 wells. These costs areincremental to BPT requirements andare based upon the following: transportof ten percent of all spent drilling fluidsysterps either to 6hore for recovery,reuse or land disposal or to an approvedocean disposal site; a 15 percentincrease in barite costs due to increasedstorage and handling costs andincreased demand for barite with lowtoxic metals content; analytical costWassociated with the toxicity limitation

and the mercury and cadmium effluentlimitations; and monitoring costs basedon the sampling frequencies presentedin Section XII of this preamble. Thedifferential cost of substituting mineraloil for diesel oil (approx. $2.10 pergallon, including storage, for the Gulf ofMexico) is not attributable to the BAToption as an incremental cost to BPT.While BPT does not explicitly prohibitthe discharge of diesel oil, the dischargeof diesel oil in any significant amounts(i.e., one volume percent or more) wouldcause a sheen on receiving waterswhich would violate the BPT prohibitionon the discharge of free oil. Therefore,the amount of mineral oil required tocomply with a proposed prohibition onthe discharge of diesel oil would beminimal, and.the associated costs wouldbe minimal.

OPTION 2-CLEARINGHOUSEAPPROACH

This option is the same as NSPSOption 2 for drilling fluids. It is basedupon the establishment by EPA of atoxicity and chemical data base ofdrilling fluid formulations and additivesthat would be used to determinewhether drilling fluid systems would-likely be acceptable for discharge.

OPTION 3-ZERO DISCHARGE

This option is the same as NSPSOption 3 for drilling fluids. It wouldrequire zero discharge for all drillingfluids, based upon transport of spentdrilling fluids to shore for recovery,reconditioning for reuse, land disposA,or transport to an approved oceandisposal site. This level of technologywould result in no discharge ofpollutants to surface waters, except atapproved ocean disposal sites.

For the estimated 1166 wells drilledannually, this option would cost $126.3million (1983 dollars). These compliancecosts are incremental to BPTrequirements, and reflect barging andmonitoring costs.

This option would result in an annualreduction of 6.2 million barrels ofdrilling fluids to surface waters, exceptat approved ocean disposal sites.

(b) Selected Option and Basis forSelection. EPA has selected Option I asthe basis for proposed BAT for drillingfluids. BAT would include the samelimitations as NSPS:

* A prohibition on the discharge offree oil, oil-based drilling fluids, anddiesel oil, all considered as "indicators"of toxic pollutants.

* A 96-hour LC-50 toxicity limitationon discharged drilling fluids of no lessthan 3.0 percent by volume of the dilutedsuspended particulate phase.

e A maximum limitation (i.e., nosingle sample to exceed) on the amountof cadmium and mercury in thedischarged drilling fluids of 1 mg/kgeach, dry weight basis.

Options 2 and 3 were rejected for thesame reasons as discussed above forNSPS.

As with NSPS, the three dischargeprohibitions on oil will serve as"indicators" of toxic pollutants. TheAgency believes it is appropriate toestablish these prohibitions as BATtoxic limitations. The primary purpose isto control the priority pollutants presentin the oils. Control on the oil content offluids could also be achieved through anumeric limitation on the conventionalpollutant "oil and grease." In fact, theAgency has included the prohibition onthe discharge of free oil as a BCTlimitation in recognition of the complexnature of the oils present in drillingfluids. However, the Agency's decisionto establish BAT limitations through thethree oil prohibitions was based on theconsideration that it would be lessdifficult and costly to comply with thesethree "indicator" limitations thannumeric limitations on each of theorganic priority pollutants present in theoils. This decision to establishlimitations on oils as indicators ofpriority pollutants is consistent with theAgency's listing of "oil and grease" as aconventional pollutant. (44 FR 44501.) Inthat notice, the Agency explained that"where toxic substances are associatedwith oil and grease, the Agency mayrequire control at BAT levels. This willbe done either by identification of oiland grease as an indicator pollutant orby establishing BAT limitations for thespecific toxic pollutant." Id. The Agencysolicits comments on its decision toestablish these indicator pollutantlimitations as BAT rather than settingnumeric limitations on the specificorganic priority pollutants orconventional pollutants. Since the oilswould be considered BAT toxicindicators, such limitations would not besubject to Section 301(c) or Section301(g) modifications.

The LC-50 toxicity limitation andlimitations on mercury and cadmiumalso are appropriate BAT limitations.Compliance with these limitations aswell as the three oil prohibitions can beachieved through product substitution.Product substitution is both atechnologically feasible andeconomically achievable means forcompliance.

Related to this option, the Agency isproposing to amend the currentdefinition of the term "no discharge offree oil." The current definition of "no

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discharge of free oil" defines the term tomean "that a discharge does not cause afilm or sheen upon or a discoloration onthe surface of the water or adjoiningshorelines or cause a sludge or emulsionto be deposited beneath the surface ofthe water or upon adjoining shorelines."This limitation was originally intendedto prohibit the discharge of drillingfluids (as well as drill cuttings and welltreatment fluids) that, when discharged,would cause a sheen on the receivingwater. The limitation was then extendedfor final BPT regulations to include deckdrainage, and the current definition ofthe term "no discharge of free oil" wasestablished to be consistent with the oildischarge provision of Section 311 of theAct. Technically, however, dischargeddrilling fluids could be considered"sludge." For this reason, the Agency isproposing to amend the currentdefinition by excluding language thatprohibits the deposition of sludgebeneath the surface of the receivingwater. This would allow the dischargeof drilling fluids, provided that othereffluent limitations are met.

The amended definition isaccompanied by a test procedure fordetermining compliance with theprohibition on free oil discharges. Thistest is the "static sheen test" used indefinition § 435.11(m) and presented inAppendix I of today's proposedregulations. This would apply to thesame waste streams that are covered bythe existing BPT prohibition, i.e., deckdrainage, drilling fluids, drill cuttings.and well treatment fluids.

The compliance monitoring procedurepreviously requiied by permits was avisual inspection of the receiving waterafter discharge. However, since theintent of the limitations is to prohibitdischarges containing free oil that willcause a sheen, the method ofdetermining compliance should examine6il 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 as in Alaskan operations.These include above-ice dischargeswhere the receiving water would be

covered with broken or solid ice, andbelow-ice discharges where the effluentstream would be obscured.

To correct for these monitoringproblems, the Agency developed analternative compliance test, the StaticSheet Test, which is presented inAppendix 1 of today's proposedregulations. 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 seawater,allowed to stand for a designated periodof time, and then viewed for a sheen.

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.

3. Drill Cuttings(a) Control and Treatment Options

Considered.

OPTION 1

Option 1 is the same as NSPS Option1 for drill cuttings. It would result in theprohibited discharge of free oil, oil-based fluids, and diesel oil in dischargeddrill cuttings. These limitations, as forthe selected option for drilling fluids, areachieved by product substitution. Therationale for these limitations is also thesame as for drilling fluids Option 1because the constituent of concern inthe drill cuttings waste stream is theresidual drilling fluid that mixes withand adheres to the drill cuttings.

For the estimated 1166 wells drilledannually, this option would result in anestimated annual cost of $8.6 million(1983 dollars) for transport of drillcuttings to shore for land disposal andfor effluent monitoring. No investmentcosts are expected to occur from thisoption. This option would result in anestimated annual reduction of at least1.3 million pounds of oil otherwisedischarged to surface waters.

OPTION 2

Option 2 is equivalent to Option 1 plusa limitation on the allowable oil contentof the discharged cuttings. This option isthe same as NSPS Option 2 for drillcuttings. The oil content limitation of 10percent maximum by weight would bebased upon drill cuttings water/detergent washer technology, asdiscussed in Section XI of this preamble.

OPTION 3

Option 3 would require zero dischargeof all drill cuttings, based upon transport

of drill cuttings to shore for recoveryand reuse or land disposa, or transportto an approved ocean disposal site. Thisoption would result in no discharge ofpollutants to surface waters, except atapproved ocean disposal sites. Thisoption is the same as NSPS Option 3 fordrill cuttings.

For the estimated 1166 wells drilledannually, this option would result inannual effluent monitoring and transportcosts of $77.1 million (1983 dollars). Thisoption would result in an annualreduction of 1.7 million barrels of drillcuttings discharged to surface waters.

(b) Selected Option and Basis forSelection. The Agency selected Option 1as the basis for proposed BAT for drillcuttings. The requirements of Option 1are comparable to those of the selectedoption for drilling fluids. This option isbased on product substitution which isboth a technologically feasible andeconomically achievable means forcompliance by the industry.

The Agency is not selecting Option 2at this time because it believes, asdiscussed above for NSPS, thatestablishing an oil content limitation ondrill cuttings may be redundant becausethe prohibition on the discharge of freeoil appears to be a more stringentlimitation. The Agency will collect andevaluate additional cuttings washerperformance data, especially withrespect to the use of mineral oil forlubricity and spotting purposes, toestablish whether an oil contentlimitation is more stringent than the freeoil limitation.

The Agency rejected Option 3, zerodischarge, because of high aggregatecompliance costs and concern f&radequate land availability for disposalas discussed above for NSPS.

4. Deck Drainage

The Agency is proposing to establishBAT for deck drainage equal to the BPTlevel of control. This would result in aprohibition on the discharge of free oilas an "indicator" to reduce or eliminatethe discharge of any toxic pollutants inthe free oil to surface waters. Thetechnology basis is oil-water separation.BAT compliance costs incremental toBPT consist of additional compliancemonitoring expenditures of $1.09 million(1983 dollars) annually, reflecting use ofthe proposed static sheet test todetermine compliance with theprohibition on the discharge of free oil.

The Agency is reserving coverage ofall other toxic and nonconventionalpollutant parameters and characteristicsfor deck drainage pending additionaldata collection and analysis. Thisadditional data will include toxic

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pollutant information and control andtreatment technology evaluation.

5. Sanitary Wastes and DomesticWastes

The Agency is not proposing toestablish BAT effluent limitations forthese waste streams because there havebeen no toxic or nonconventionalpollutants of concern identified insanitary or domestic wastes.

6. Produced SandThe Agency is proposing to establish

a BAT prohibition on the discharge offree oil for produced sand as an"indicator" to reduce or eliminate thedischarge of any toxic pollutants in thefree oil to surface waters. Thetechnology basis for this limitation iswater or solvent wash of produced sandprior to discharge, or transport ofproduced sand to shore for landdisposal. Because this waste stream isof low volume and because mostfacilities currently practice eitherwashing or land disposal, the Agencydid not attribute any compliance coststo this proposed limitation, except fornominal compliance monitoringexpenses to perform the static sheen testto determine the presence of free oil.

The Agency is reserving coverage ofall other toxic and nonconventionalpollutant parameters and characteristicsfor produced sand pending additionaldata collection and analysis. Thisadditional data will include toxicpollutant information and control andtreatment technology evaluation.

7. Well Treatment Fluids

The Agency is proposing to establisha BAT prohibition on the discharge offree oil for well treatment fluids as an"indicator" to reduce or eliminate thedischarge of any toxic pollutants in thefree oil tn surface waters. This is equalto the BPT level of control. Therefore,there are no compliance costsincremental to BPT, except for nominalcompliance monitoring expenses toperform the static sheen test todetermine the presence of free oil.

The Agency is reserving BATcoverage of all other pollutants andcharacteristics for well treatment fluidspending additional data collection andevaluation. This additional data willinclude toxic and noncor'ventionalpollutants information and control andtreatment technology evaluation.

C. Best Conventional Technology

The 1977 amendments added section301(b)(4)(E) to the Act, establishing"best conventional pollutant controltechnology" (BCT) for discharges ofconventional pollutants from existing

industrial point sources. Conventionalpollutants are those defined in section304(b)(4)-BOD, TSS, fecal coliform andpH-and any additional pollutantsdefined by the Administrator as"conventional." On July 30, 1979, EPAdesignated "oil and grease" as aconventional pollutant (44 FR 44501].

BCT is not an additional limitation;rather it replaces BAT for the control ofconventional pollutants. BCT requiresthat limitations for conventionalpollutants be assessed in light of "cost-reasonableness." EPA publishedproposed rules for BCT on October 29,1982 (47 FR 49176). These proposed rulesset forth a revised procedure whichincludes two tests to determine thereasonableness of costs incurred tocomply with candidate BCT -technologies. These cost tests are the"POTW test" and the "industry costtest." On September 20, 1984, EPApublished a "notice of data availability"concerning the proposed BCTregulations (49 FR 37046).

1. Produced Water

(a) Control and Treatment OptionsConsidered. EPA examined threetreatment options for removingconventional pollutants from producedwater in relation to the proposed BCTmethodology.

OPTION 1-IMPROVEDPERFORMANCE OF BPT

This option would require effluentlimitations based on the improvedperformance of BPT technology. Aspresented above for NSPS option 1, thislevel of technology would result inadditional reductions of oil and greasebeyond the BPT level of control. Adischarge limitation of 59 mg/Imaximum (no single sample to exceed)for oil and grease would result from thisoption.

OPTION 2-FILTRATION ON SITE

This option would require effluentlimitations based on granular mediafiltration as an add-on technology toBPT. Filtration equipment would beinstalled on the platform with thetreated effluent being discharged at theplatform. This level of technology wouldresult in additional reductions ofconventional pollutants beyond the BPTlevel of control. Effluent limitations of 20mg/I monthly average and 30 mg/I dailymaximum for oil and grease wouldresult from this option.

OPTION 3-FILTRATION ONSHORE

This option is the same as Option 2except it is applicable to facilities whichpresently separate produced water fromhydrocarbon product at the platform,

pipe the produced water to shore-fortreatment to meet BPT effluentlimitations, and discharge the treatedeffluent to surface waters.

(b) Selected Option and Basis forSelection. The Agency rejected theoptions presented above and isproposing to establish BCT for producedwater at the BPT level of control. Thiswould result in effluent limitations of 48mg/I monthly average and 72 mg/l dailymaximum for oil and grease, based uponoil water separation technologies. TheAgency rejected Options 1 through 3because they all fail the first part of theAgency's proposed BCT cost test (the"POTW test").

For Option 1, the Agency was uriableto directly perform the POTW testbecause the Agency lacks sufficientinformation to accurately estimate theincremental cost of improved BPTperformance (see section XI.A.1(a)above); this cost is necessary in order toperform the POTW test. Therefore, theAgency analyzed this option bydetermining the maximum dollarexpenditure per day that modelplatforms could incur to implement thisoption without exceeding the POTW testbenchmark.

The maximum cost per pound ofconventional pollutant removal wherebythe "POTW test" will be passed ispresented in the BCT "notice of dataavailability" referenced above. Thesemaximum costs were used to calculatethe total dollars that could be expendedat each of the 32 model platforms tocomply with this option and still passthe "POTW test." This wasaccomplished by multiplying the poundsof conventional pollutants that would beremoved by BCT Option I technologyfor each of the 32 model platforms usedfor this study by the benchmark cost perpound presented in the "notice of dataavailability."

This total cost for each modelplatform ranged from $0.79 per day forthe smallest model platform to $182 perday for the largest model platform. TheAgency believes that the cost ofimplementing Option 1 is minimal,although not as low as the range of dailycosts derived by the above procedure.Therefore, the Agency rejected Option 1because it fails the POTW cost test.

For Options 2 and 3, the Agencycalculated compliance costs(incremental to BPT) for each of 32model platforms and then performed thePOTW test for each model size platform.The range in costs per pound ofconventional pollutant removed beyondBPT for Options 2 and 3 based on modelplatform size, is as follows:

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Lowestcost-dollars

perpound

removej(1980

dollars)

Highestcost-dollars

perpoundremoved(1980

dollars)

O ption 2 ................................................... 64 71O ption 3 ................................................... 54 6

These costs were compared with thefourth quarter, 1980 POTW proposedbenchmark of $1.04 per pound ofconventional pollutant removed. ThePOTW test failed fop Options 2 and 3 forall of the model platforms. Therefore,EPA rejected these options for the BCTlevel of control. The Agency intends toevaluate reinjection technology for BCTafter collection of certain additionaltechnology and cost information (seeSection XX) prior to promulgation of thefinal regulations. The Agency may alsore-evaluate the proposed BCTlimitations for produced water when thefinal BCT methodology is promulgated.

2. Drilling Fluids, Drill Cuttings, DeckDrainage and Well Treatment Fluids

With one exception, the Agency isreserving BCT requirements for drillingfluids, drill cuttings, deck drainage andwell treatment fluids until finalpromulgation of the general BCTmethodology. The exception is aprohibition on the discharge of free oil.This limitation is equal to the BPT levelof control for these waste streams.Therefore, no incremental costs areassociated with this proposed BCTlimitation. Because BCT is proposed tobe equal to BPT, the free oil dischargeprohibition will pass any BCT cost test.When the final BCT methodology ispromulgated, the Agency may proposeto establish BCT limitations for otherconventional pollutants for these wastestreams. At this time, the Agency issoliciting comment on what pollutants indrilling fluid and drill cuttings wastestreams should be consideredconventional pollutants. Specifically, theAgency solicits comments on whetherthe solids components of the fluids andcuttings should be considered totalsuspended solids.

3. Domestic and Sanitary Wastes

The Agency is proposing BCTcoverage for sanitary and domesticwastes equal to the BPT level of control.The Agency is proposing a residualchlorine effluent limitation for facilitiescontinuously manned by 10 or morepersons of 1 mg/1 maximum andmaintained as close to this level aspossible in sanitary discharges to 'control fecal coliform. Residual chlorineis being treated as. a BCT parameter

because its purpose is to control theconventional pollutant fecal coliform.

The proposed BCT limitation fordomestic wastes from all facilities andsanitary wastes from facilitiescontinuously manned by 9 or fewerpersons or manned intermittently by anynumber of persons is "no discharge offloating solids." No compliance costsincremental to BPT are associated withthe proposed BCT limitations. Since noadditional costs will be incurred theselimitations pass the BCT cost tests.

4. Produced Sand

With one exception, the Agency isreserving BCT coverage for producedsand until the promulgation of the finalBCT methodology. The Agency isproposing a BCT limitation that wouldprohibit the discharge of free oil forproduced sand discharges. As discussedabove for BAT, this limitation wouldresult in negligible compliance costs.

The Agency solicits comment on otherpollutants in the produced sand wastestream that should be considered forregulation at the BCT level of control.

D. Best Practicable Technology

As discussed above for NSPS andBAT, the Agency is proposing to amendthe definition of the term "no dischargeof free oil" and the test procedure fordetermining compliance with theprohibition of free oil discharges. Forconsistency, the Agency is proposing thesame change to the existing BPTregulations. This change does not affectthe conclusion that the current BPTlimitation of no discharge of free oil maybe met through use of the bestpracticable control technology currentlyavailable and that the costs of thattechnology are justified by the effluentreduction benefits.

XII. Cost and Economic Impact

A. Treatment Technology Costs

The costs of implementing thetreatment options considered for today'sproposed regulations were developedthrough compilation of cost dataobtained from equipment manufacturers,the offshore oil and gas extractionindustry, cost estimating manuals, andby the application of standardengineering data and cost estimationtechniques.

Costs were determined for 32 modelplatform sizes. Treatment componentswere sized and costed for each modelplatform for all treatment options whichwere 6onsidered to be technologicallyfeasible. In addition, a typical or modelwell depth was established so that costestimates accounted for situations

where well depth affected pollutioncontrol costs.

Various assumptions were made onthe area required for installation ofequipment, cost of new platform space,cost of land used for onshore treatment,and piping and energy costs. TheAgency estimated that from 17 to 84percent of new offshore productionfacilities covered by this regulationwould reinject onshore, depending upongeographic location, e.g., Gulf of Mexico,California, Alaska.

Energy costs were determined basedon pumping requirements and treatmentfacility operation. Natural gas wasassumed to be the source of energy topower either electrical generation orprime movers for waste treatment onplatforms, with the cost of the naturalgas at commercial value. Natural gaswas the chosen fuel source because ofits availability and because airemissions from natural gas combustionare cleaner than those from diesel fuel.For onshore treatment installations, useof locally generated electrical powerwas assumed, at commercial rates.

The costs of barging and land disposalwere obtained from barge operators, oilindustry contacts, and landfill operators.Dry wells were assumed to be availablefor use as injection wells for producedwater. Exhausted production wells wereassumed not to be available. However,additional cost savings could be realizedby using exhausted production wells forinjection of produced water. Theseassumptions were based on API drillingstatistics for the Gulf of Mexico anddiscussions with state officials.

To determine the installed cost ofequipment on platforms, multipliers of3.5 times the equipment purchase costwere used for skid-mounted equipmentand 4.0 times the equipment purchasecost for items shipped loose. Thesefactors were supplied by an engineeringconsultant to OOC in a report titledDetermination of Best PracticableControl Technology Currently Availableto Remove Oil from Water Producedwith Oil and Gas, Brown and Root, Inc.,March 1974. EPA solicits comments onthe reasonableness of these factors usedto estimate installed costs.

Geographical factors were also usedto translate the cost from the baselocation, the Gulf of Mexico (multiplier=1), to Alaska, the California Coast andthe Atlantic Coast. The following are thecost multipliers used:

Location Capital cost Applicable to-Locationmultiplier

Atlantic Coast .......................

California Coast ...................

1.6 Equipment andwells.

1.6 Do.

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Location Capital costmultiplier Applicale to-

Alaska:Norton Basin ................ 3.5 Do.Beaufort Sea ............... 3.5 Do.Bristol Bay ................... 3.5 Do.Gulf of Alaska ............. 3.5 Do.Cook Inlet/Sherikof 2.0 Equipment.Strait.

Cook InletlShelikof 2.5 Wells.Strait.

EPA also solicits comments on thereasonableness of these cost multipliers.

The Agency did not include potentialcosts for compliance with theunderground injection control (UIC)program administered under the SafeDrinking Water Act (42 U.S.C. 300f etseq.]. The Agency invites comments andsupporting data on the impacts of UICrequirements for onshore reinjectionincluding the costs of complying withthese requirements.

C. Economic Impact

1. Introduction

The Agency's economic impactassessment is set forth in the EconomicImpact Analysis of Proposed EffluentLimitations and Standards ofPerformance for the Offshore Oil andGas Industry. (EPA 440/2-85/003). Thisreport details the investment andannualized costs for the industry as awhole and for facilities covered by theoffshore segment. The report alsoestimates the probable economic effectof compliance costs in terms of prices,Federal and State revenues, productionlevels, employment, and internationaltrade effects and profitability.

EPA has also conducted an analysisof the cost-effectiveness of alternativetreatment technologies that removetoxic pollutants from produced water.The results of this cost-effectivenessanalysis are expressed in terms of theincremental removal cost per pound-equivalent, where differences in toxicityamong the pollutants found are takeninto account through the use of toxicweighting factors. In this analysis, a

None of the technologies studied inthe development of these proposedregulations is considered to beinnovative. All of the controls describedin this preamble and in greater detail inthe Development Document have eitherbeen used or investigated for use in thisindustry and do not represent majorprocess changes.

B. Compliance Monitoring Frequenciesand Costs

The Agency has estimated compliancemonitoring costs for a facility whereboth development and productionoperations are being performed. Assuch, the total monitoring costspresented below are conservative. TheBAT compliance monitoring costs fordrilling fluids and all sheen tests are themonitoring costs that are incremental toexisting BPT monitoring costs.

pound-equivalent is calculated bymultiplying the number of pounds ofpollutant discharged by a weightingfactor for that pollutant. The weightingfactor is equal to the water qualitycriterion for a standard pollutant(copper), divided by the Water qualitycriterion for the pollutant beingevaluated. The cost per pound-equivalent removed would be lowerwhen a highly toxic pollutant isremoved. This analysis is included inthe record of this rulemaking, and istitled Cost Effectiveness Analysis ofProposed Regulations for the OffshoreOil and Gas Industry. Copies of thisreport may be obtained from theeconomic analysis staff referenced inthe Addresses section of this preamble.

2. Impacts

a. Basis of Analysis. The costs andeconomic impacts associated withtoday's proposed regulations differdepending on whether drilling orproduction operations are analyzed.Costs to control drilling related effluentsare the same for existing sourceplatforms and for new platforms.

Additional costs from production relatedeffluents, however, arise from the zerodischarge requirement for certain newsource facilities.

Production related effluents atexisting facilities would be regulated tithe BPT level of control. Also, forexisting source production facilities, theproposed regulations would prohibit thedischarge of free oil for produced sanddischarges. As explained in SectionXI.B, no compliance costs are attributedto this proposed limitation, except fornominal compliance monitoringexpenses.

The economic analysis of drillingoperations is based on the total numberof exploratory, delineation anddevelopment wells which the Agencyexpects to be drilled each year. Offshoredrilling operations occur primarily in theGulf of Mexico along the Texas andLouisiana coasts although increasingefforts are being made in offshoreCalifornia and Alaska, and, to a lesserextent, in the Atlantic. The averagenumber of wells drilled annually overthe past ten years is 1166; the totalannual footage drilled is 11 million feet.All of the wells drilled for exploratory,delineation, and development purposesare covered by the proposed regulation.

The analysis of production operationsis based on the number of platformsprojected to be built between 1986 andthe year 2000. By the year 2000, newsource oil and gas development shouldhave stabilized such that the rate ofgrowth of new facilities should equal therate of obsolesence of facilities alreadycovered by the regulation. EPA expects833 new platforms to be built between1986 and the year 2000. EPA based itsestimates for platform and welldevelopment on Department of Energyprojections of future energy production,Department of Interior historical data,and on industry estimates. Of the 833new platforms, 132 are expected to belocated in water depths that would besubject to the zero dischargerequirement for produced water. Theremaining platforms would be subject tothe oil and grease standard of 59 mg/1maximum for produced waterdischarges.

b. Aggregate Impacts and Costs. Thecombined annualized cost of today'sproposed BCT, BAT and NSPSregulations is $91.5 million (1983 dollars)in the year 2000. The capital investmentfor these proposed requirements is $18.6million (in 1983 dollars). No pricechanges will result due to thisregulation. No curtailment of oil or gasproduction is expected. State andFederal lease revenues are expected todecline by $49.1 million in the year 2000

Cost persempl forCoat perWaste stream Analyses sample for Frequency Cmontt

analysismotand labor

Produced water ........................................... Oil and grease ........................................... 1$40 1/,week ............. $640Dulling fluids ................... B ioassay (1C-50) .................... $1,000 1/month . 1,000

Mercury, total ............................................. $50 1/month . 50Cadmium, total ............................................ $50 1/month 1 50Static sheen ............................................... $25 3/week .......... 300

Drilling cuttings ................................................ do ........................................................... $25 daily .................. 750Deck drainage ................................................. do ............................................................ $25 . do ................ 750Produced sand ................................................. do...................... $25 . do .............. 750Well treatment fluids .......... .................... do ............................................................ $25 1 /month . 25Sanitary M91M and Domestic wastes. Floating solids ............................................. nil daily .................. 0Sanitary M10 .............................................. Residual chlorine ...................................... $20 1/month ........... 20

Four samples per determination.Twice per well.As needed.

34615


(1983 dollars) if companies reduce theirlease bid prices. The effect of reducedbid prices is not expected to exceed 0.1percent of total revenues for Statesaffected by the proposed option. Noemployment or international tradeeffects are projected.

Between 85 to 95 percent of newfacility construction is likely to occur onnew lease tracts. These operationscannot pass the additional cost of theregulation on to customers in the form ofprice increases, since the price isdetermined in a large internationalmarket. The operations are expected topass the additional cost of the regulationon to the State and Federal governmentin the form of lower lease bids. TheAgency's analysis projected the revenueeffects on the States and Federalgovernment.

Some new drilling and platformconstruction is likely to occur onexisting lease tracts. These operationsmust absorb the costs of the regulation,since the costs cannot be passed on inthe form of higher prices or lower leasebids.

c. Methodology. The Agency used anet present value analysis to calculatewhether offshore developmentoperations could remain profitable afterregulatory costs were incurred. Costsand revenues were projected over thelife of the model project first based onthe existing BPT requirements. Then theregulatory costs were added to thesebaseline costs to determine if modelplatforms remained profitable. EPA used32 model platforms representingoperations in the Gulf of Mexico,California Coast, Alaska and theAtlantic Coast. Distinct' technical andeconomic characteristics for facilities inthese areas were developed. Costsincluded in the baseline condition werethose associated with leasing,exploration, delineation, developmentand production operations.

To assess the impact on offshore oiland gas companies, the Agencydeveloped two representative companyfinancial profiles: one for majorintegrated companies and one forindependents. Pre- and post-regulationbalance sheets were developed and theeffect of the regulatory costs on theirfinancial condition was assessed.3. Best Conventional Pollutant ControlTechnology

BCT is either proposed equal toexisting BPT requirements or reservedfor this proposed rulemaking. No costsor impacts are projected as a result oftoday's proposal of BCT.

4. Best Available TechnologyEconomically Achievable

Because the Agency is reservingcoverage of produced water for BAT, nocosts or impacts are projected for thedischarge of produced water by existingplatforms.

Exploratory, delineation, anddevelopment operations will incur acombined cost of $35.9 million annuallyto comply with the drilling fluids andcuttings limitations (1983 dollars). Nocapital investment will need to be madeto meet these limitations. The costs arebased on an estimated annual drilledfootage of 11.2 million and includeincremental costs of clean barite fordrilling fluids as well as monitoring andbarging costs. Monitoring and testingcosts total $5.0 million and are based onthe sampling frequency presented inPart B of this section. Costs oftransportation to shore and landdisposal total $20.2 million; these costsare expected to occur when drilling fluiddischarges exceed either the LC-50limitation or mercury or cadmiumlimitations, or when fluids or cuttingsdischarges would not pass the staticsheen test. An estimated 10 percent ofall drilling operations are expected toincur transport costs. Barite costs total$10.7 million and are based on anassumed price increase of 15 percent toreflect the combined increased storageand handling costs as well as increasesin price of blended barite.

To calculate the decline in the rate ofreturn associated with the BATlimitation, the Agency used the netpresent value analysis described abovebut used the BPT requirements as abaseline. The decline in rate of return ofthe model platforms was approximately0.1 percent. No curtailment in drillingactivities is expected to occur from theproposed requirements. No effect on oiland-gas prices, employment orinternational trade is projected. TheAgency finds these costs to beeconomically achievable for the oil andgas industry.

5. New Source Performance Standards

Incremental costs of compliance withthe proposed regulation will arise onlyfrom production operations. Control ofeffluents from drilling operations at newsources is no more stringent than thatfor existing sources; therefore, noincremental costs are assigned to newsources.

Of the 833 platforms projected to bebuilt between 1986 and the year 2000,701 would be subject to the proposed 59mg/l oil and grease standard forproduced water. Incremental costs forplatforms complying with the 59 mg/l

standard are expected to be de minimisand, therefore, are considered to beeconomically achievable. This standardrepresents improved operation andmaintenance of existing BPT treatmenttechnology. An estimated 126 of theother 132 facilities are expected to incuran annualized cost of $55.6 million (1983dollars) to comply with the zerodischarge requirement for producedwater. This annualized cost reflects thecost for 124 new platforms operating inthe year 2000 in water depths of 20meters or less in the Gulf of Mexico andtwo platforms located in 50 meters orless of water for the California Coast.The six platforms projected in 10 metersor less of water in Alaska must complywith an existing zero dischargerequirement and are not expected toincur additional costs associated withtheir produced water effluent. Theinvestment cost for facilities in the year2000 is $18.6 million (1983 dollars). Theinvestment cost applies to new facilitiesprojected for the year 2000 in the depthcoverage areas.

In calculatihg the costs associatedwith the zero discharge requirement, theAgency assumed that from 20 to 50percent of all wells drilled are dry andbetween 7 and 25 percent of all drywells are usable for injection. TheAgency also assumed that between 17and 84 percent of the platforms willreinject onshore depending upondistances from shore. The onshorereinjection costs include the drilling ofall injection wells necessary to handleproduced water volumes. EPA does notexpect any of the facilities that areprojected to be placed in the depthcoverage areas to become umprofitabledue to reinjection requirements.

The majority of new facilties will bebuilt in new lease tracts. Theseoperations cannot pass the additionalcosts of the regulation on to theircustomers as price increases becausethey represent only a very smallsegment of the international market inwhich prices are determined. However,they are not expected to experiencesignificant declines in profits becausethey are expected to pass any additionalcosts of the regulation on to state andfederal governments through lower leaseprices. Thus, for the majority of newplatforms, the impact of the regulationswould be to reduce federal and staterevenues. The reduction in revenues forthe affected states is not expected toexceed 0.1 percent.

For the 5 to 15 percent of newplatforms to be constructed onexistinglease tracts, the cost of the regulationcannot be passed on as reduced leasebids. As a result, the rate of return for

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Federal Register / Vol. 50; No. 165 / Monday, August 26, 1985 / Proposed Rules

these operations is expected to declinefrom 0.4 to 4.5 percent (with an averagedecline of 1.8 percent).

The Agency projects no net decline inenergy production as a result of the zerodischarge requirement because themajority of platforms are not expectedto experience a change in productionlevels. Some platforms may shut down ayear early and therefore produce less oilthan they would have without theregulation. Approximately one-third ofthe model platforms are projected toshut down early due to an increase inthe water/oil ratio in produced water,which will reduce profitability. Thosethat do are not expected to shut downmore than a year early and the resultantdecline in production is less than 0.1percent of total model projectproduction. Platforms able to use-waterflooding may benefit fromreinjection of produced water. As wateris injected into a producing formation,increased pressure causes oil productionincreases. On balance, these productionchanges are expected to offset eachother.

The Agency projects no employmentor international trade effects as a resultof this regulation.XIII. Nonwater Quality EnvironmentalImpact

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 hasconsidered the effect of theseregulations on air pollution, solid wastegeneration, water scarcity, and energyconsumption. This proposal wascirculated to and reviewed by Agencypersonnel responsible for nonwaterquality environmental programs. Whileit is difficult to balance pollutionproblems against each other and againstenergy use, the Agency is proposingregulations that it believes best serveoften competing national goals.

The following are the nonwaterquality environmental impactsassociated with today's proposedregulations:

A. Energy Requirements

Additional energy requirementsimposed by these regulations are dueprimarily to the filtration and pumpingof produced water into injection wellsfor those new source facilities subject tothe zero discharge standard. The energyrequirements for the 132 new sourceplatforms that would be required to

reinject produced water totalapproximately 170 million kilowatt-hours per year. This representsapproximately 0.05 percent of the energycontent of the produced hydrocarbonsfrom these facilities. Therefore, thesmall incremental energy requirementsfor reinjection of produced water willnot significantly affect the cost ofpollution control, nor will theymeasurably affect energy supplies.

There are no measurable increases inenergy requirements beyond BAT forthose new sources that would be.subjectto improved performance of BPTtechnology for produced water.

Today's proposed NSPS regulationsfor waste streams other than producedwater and the proposed BAT regulationsare based primarily on productsubstitution techniques and practicesthat do not involve the expenditure ofmeasureable amounts of energy.

B. Air Pollution

This Agency estimated air pollutionfrom offshore oil and gas platforms in areport titled Atmospheric Emissionsfrom Offshore Oil and Gas Developmentand Production, June 1977 (EPA 450/3-77-026). Emissions of hydrocarbons,hydrogen sulfide, nitrogen oxide andsulfur dioxides are estimated in thisreport. Presently there are no nationalstandards that directly regulateemissions from offshore oil and gasfacilities.

Sources of air pollution include leaks,oil water separators, dissolved airflotation units, painting apparatus,storage tanks and diesel or gas enginesfor generating power. The followingdiscussion addresses air pollutionaspects of the proposed regulations.

When additional pumping is required,due to the application of a particularpollution control technology forproduced water, additional airemissions will be created due to-the useof fuel to power either electricgenerators or prime movers. However,the use of gas turbine engines projectedfor the majority of sites offshore shouldresult in the least emissions to theatmosphere. If treatment facilities ,arelocated onshore, power would be,obtained from local electric powercompanies, with no air emissions fromon-site power generation.

C. Solid Waste

Operators of offshore platforms coulddischarge drilling fluids and drillcuttings in accordance with today'sproposed regulations and any additional403(c) considerations. In the majority ofsituations, drilling fluids and additivescan be selected such that they wouldachieve the effluent limitations. As such,

minimal solid waste generation foronshore disposal is expected to resultfrom these regulations.

Section 3001 of the ResourceConservation and Recovery Act (RCRA)presently exempts offshore drillingwastes from compliance with solidwaste disposal regulations. Section 3001of RCRA states that "drilling fluids,produced water, and other wastesassociated with the exploration,development, or production of crude oilor natural gas or geothermal energyshall be subject only to existing state orfederal regulatory programs in lieu ofSubtitle C [regulation of land disposedhazardous wastes] * * *."

Section 8002 of RCRA prescribes thatthese exempt waste streams beinvestigated by the EPA's Office of SolidWaste and that a final determination bemade on their status of exemption fromRCRA. The Agency is currentlypreparing a preliminary assessment ofthese wastes.

Minimal additional solid waste isassociated with filtration when used totreat produced water prior toreinjection. The final disposition of thefiltration wastes would be in approvedland fills, except for platforms inoffshore California waters wherecontrolled ocean disposal of drillingwastes may be allowed.

D. Consumptive Water Loss

No consumptive water loss isexpected as a result of these regulations.

XIV. New Source Definition

The exploration, development,.andproduction of oil and gas in offshorewaters involves operations sometimesunique from normal industrialoperations performed on land. Thedefinition section of this regulationincludes a definition of "new source"appropriate for this subcategory of theoil and gas industry. While theprovisions in the NPDES regulations thatdefine new source (40 CFR 122.2) andestablish criteria for a new sourcedetermination (40 CFR 122.29(b)) areapplicable to this subcategory, twoterms, "water area" and "significant sitepreparation work", are defined in thissubcategory-specific new sourcedefinition in order to give the termsmeanings relevant to offshore oil andgas operations. The special definitionsin today's proposed regulations areconsistent with § 122.29(b)(1) whichprovides that § 122.2 and 122.29(b) shallapply "Except as otherwise provided inan applicable new source performancestandard." See 49 FR 38048 (September26, 1984).

34617


Before discussing the two specialdefinitions, a brief discussion follows onthe scope of the term "new source" forthe offshore oil and gas industry. Theterm "new source" is applicable to allactivities covered by the offshoresubcategory. This includes mobile and/or fixed exploratory and developmentdrilling operations as well as productionoperations. Coverage of all suchoffshore oil and gas operations isrequired by Section 306 of the Act.

Section 306(a)(2) defines a "newsource" to mean "any source, theconstruction of which is commenced"after publication of the proposed NSPSif such standards are promulgatedconsistent with section 306. The Actdefines "source" to mean any "facility• . . from which there is or may be thedischarge of pollutants" and"construction" to mean "any placement,assembly, or installation of facilities orequipment ... at the premises wheresuch equipment will be used." The term"source" clearly would include alldrilling rigs and platforms as well asproduction platforms. The breadth of theterm "construction," which encompasesthe concept of "placement" of"equipment" at the "premises," wouldinclude the location and commencementof drilling or production operations at anoffshore site to be "construction" of anew source. This is a critical distinction.Drilling rigs obviously are moved fromsite to site for several years. Productionplatforms are built on shore andtransported to an offshore site. Theappropriate reading of section 306(a)(5)would not make the date of building therig or platform determinative of whetherthe rig or platform was a new source,but rather when the rig or platform wasplaced at the offshore site where thedrilling and production activity anddischarge would occur. Therefore,drilling operations that commence afterthe NSPS are effective, even ifperformed by an existing mobile rig,would be new sources, coming withinthe definition of "constructed" by"placement" of "equipment" at the.premises."

Similarly, a mobile drilling ri' whichcarries the drilling equipment would beconsidered "placed" at the location itanchors for drilling, which would be the"premises." The Agency considers thedrilling rig to be the "facility ... fromwhich there is or may be the dischargeof pollutants" within the meaning ofSection 306(a)(3). The same reasoningapplies to development drilling rigs andstructures and production structures,platforms or equipment. The criticaldetermination of whether a source is a"new source" is the date of placement

and commencement of operations, notthe date the source orginally was built.

The first special term that is definedin these proposed regulations is "waterarea" as used in the term "site" in§ 122.29(b). The term "site" is defined in§ 122.2 to include the "water area"where a facility is "physically located"or an activity is "conducted." For thepurposes of determining the "site" ofnew source offshore oil and gasoperations, the Agency is proposing todefine "water area" to mean the specificgeographical location where theexploration, development, or productionactivity is conducted, including thewater column and ocean floor beneathsuch activities. Therefore, if a newplatform is built at or'moved from adifferent location, it will be considered anew source when placed at the new sitewhere its oil and gas activities takeplace. Even if the platform is placedadjacent to an existing platform the newplatform will still be considered a "newsource," occupying a new "water area"and therefore a new site.

EPA considered defining "water area"as a larger body of water, such as alease block area. This alternative wasrejected because such an artificialdistinction would allow thecommencement of many additional oiland gas activities (not considered to be"new sources") in an area merely byvirtue of the fact that an existing activitywas currently operating in the leaseblock. This result is inconsistent withthe definitions and purpose of Section306 of the Act. Under Section 306 a "newsource" means "cny source" theconstruction of which begins after theAgency publishes a NSPS.

The second special term for whichEPA is proposing a special definition is"significant site preparation work." Asexplained above, the date of"placement" of a rig or platform isdeterminative of when a source isconsidered to be "constructed." Thedate of "placement" (i.e., "construction"]may be earlier under the provision of 40CFR § 122.29(b)(4) which definesconstruction as being commenced when"signifcant site preparation work" hasbeen done at a site. The effect of theproposed definition for "significant sitepreparation work" is important indetermining what individual sourceswould be considered to have"commenced construction" orcommenced "placement" prior to thepublication of the NSPS and thereforewould not be considered a new source.EPA is proposing to define this term tomean the processes of clearing andpreparing an area of the ocean floor forpurposes of constructing or placing a

development or production facility on orover the site. Therefore, if clearing orpreparation of an area for developmentor production had occurred at a siteprior to the publication of the NSPS,then subsequent development andproduction activities at that site wouldnot be considered a new source. Thesignificance of this definition is thatexploration activities at a site prior tothe effective date of the NSPS are notconsidered significant site preparationwork. Therefore, if only exploratorydrilling had been performed at a site,subsequent development and productionactivities would not be "grandfatheredin" as existing sources at the site butrather would be considered "newsources." The Agency does not considerexploratory activities to be "significantsite preparation work" because suchactivities are not necessarily followedby development or production activitiesat a site. Even when exploratory drillingultimately leads to drilling andproduction activities, the latter may notbe commenced for months or years afterthe exploratory drilling is completed.-The purpose of this provision is to allowa future source to be considered anexisting source if "significant sitepreparation work," thereby evidencingan intent to establish full-scaleoperations at a site, had been performedprior to NSPS becoming effective. Whilea development or production platformwould not be built unless an exploratorywell had been drilled, exploration wellsare drilled at vastly more sites and canprecede development by months oryears.

Another provision of § 122.29(b)(4)regarding when construction of a newsource has commenced, provides thatconstruction has commenced if theowner or operator has "entered into abinding contractual obligation for thepurchase of facilities or equipmentwhich are intended to be used in itsoperation within a reasonable time."The Agency is not proposing a specialdefinition of this provision believing itshould appropriately be a decision forthe permit writer. However, the Agencycarefully has considered this provisionand is providing the following generalguidance concerning the properapplication of the provision for thespecial circumstances of offshore oil andgas activities.

A common practice in the industry isfor oil companies to enter into long-termcontracts with independent drillingcompanies. These contracts may requirethat the drilling company will provide itsservices for a specified number of wellsover a period of months or years. Theexact site for the exploratory drilling

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services may not be specified. TheAgency believes such contracts wouldappropriately fall within the provision of§ 122.29(b)(4)(ii) thereby making thedrilling activities under those contractsexisting sources, not new sources. Suchcontracts generally do not or cannotspecify the exact site for futureexploratory drilling.

The situation generally is not thesame for development drilling orproduction activities. Contracts for theseactivities usually specify the site whereactivities are to be conducted orfacilities placed. Therefore, a contractthat meets the conditions of§ 122.29(b)(4)(ii) for an exact siteprobably would not be considered anew source. However, a generalcontract for construction or use of adevelopment or production platformwith no indication of the location whereit would be placed or used would notqualify to make a future selected site forits use an existing source. An oppositeresult would allow companies to movean existing platform or use old platformsat new sites in shallow water areasthereby avoiding the NSPS zerodischarge requirement for producedwater. Such a result would be contraryto the purpose of establishing NSPS.

An issue of continuing concern underthe Clean Water Act has been whetherNSPS must be applied after theirproposal or only after theirpromulgation. Section 306(a)(1) of theAct provides that a "new source" is asource, the construction of whichcommences after proposal of NSPS ifsuch NSPS are promulgated inaccordance with section 306. Section306(b)(1)(B) requires promulgationwithin 120 days of proposal. EPA'simplementing regulations for directdischargers provide that a new sourcemeans a source, the construction ofwhich commenced either after proposalif the NSPS are promulgated within 120days of after promulgation in all othercases. Section 122.2.

EPA does not intend that the NSPS forthis subcategory shall be effective untilthey are promulgated unless they arepromulgated within 120 days of proposalin which case the effective date wouldbe the date of proposal. Therefore, nosource will be considered a "newsource" subject to NSPS until theAgency promulgates the NSPS. Thisdecision is consistent with the Agency'sdefinition of "new source" in 40 CFR§ 122.2 since for the reasons discussedbelow the Agency will not be able topromulgate NSPS within 120 days ofproposal. While the Agency continues tobelieve the definition of new source in§ 122.2 is appropriate and consistent

with the Act, the Third Circuit Court ofAppeals has twice in NAMFv. EPA, 719F.2d 624, 641 (3rd Cir. 1983) andPennsylvania Department ofEnvironmental Resources v. EPA, 618F.2d 991 (3rd Cir. 1980), held that as ageneral matter EPA's new sourcestandards shall be applied as o'f theirdate of proposal. However, the Court inthose cases also recognized that theremay be circumstances, such as caseswhere "substantial changes" may occurbetween proposal and promulgation thatwould justify an NSPS effective date asthe date of promulgation. See NAMF v.EPA, 719 F.2d at 643 n.20. The Agencybelieves that today's proposal. is such acase, as discussed below.

First, one of the issues in thisrulemaking is the definition of "newsource." The Agency has solicited publiccomment on the proposed definition ofnew source. The agency's final decisionon the definition of new source for thissubcategory will be critical to knowingwhat facilities must comply with theNSPS. Because the proposed definitionof NSPS may change upon promulgation,individual dischargers would be unableto determine their status for anextended period of time. This wouldhinder operational planning during theperiod.

Second, the proposed standards maychange on promulgation. After proposaland prior to promulgation, the Agencywill be collecting substantial additionaldata on the proposed standards and willbe reconsidering its decisions. In light ofthis fact and the substantial number ofexpected comments, it seemsinappropriate to require compliancewith the proposed NSPS.

Finally, one of the primary effects of adecision to apply NSPS at the date ofproposal would be that the NationalEnvironmental Policy Act (NEPA) wouldapply to the action of issuing the permitfor the new source. For new lease areas,the Department of Interior ("DOI")already is preparing environmentalimpact statements (EIS) that considerthe proposed oil and gas operations inthe lease areas. EPA has entered into amemorandum of understanding withDOI providing for EPA participation inthe EIS process. Therefore, for newfederal lease areas, the provisions ofNEPA are being applied.

XV. Best Management Practices

Section 304(e) of the Clean Water Actauthorizes the Administrator toprescribe "best management practices"("BMP") to control "plant site runoff,spillage or leaks, sludge or wastedisposal, and drainage from rawmaterial storage." Section 402(a)(1) andNPDES regulations (40 CFR 122) also

provide for best management practicesto control or abate the discharge ofpollutants when numeric effluentlimitations are infeasible. However, theAdministrator may prescribe BMP's onlywhere he finds that they are needed toprevent "significant amounts" of toxic orhazardous pollutants from enteringnavigable waters.

In the offshore oil and gas industrythere are various types of wastes thatmay be affected by the application ofBMP's in NPDES permits. These includedeck drainage and leaks and spills fromvarious sources. The amount of.contaminated deck drainage can bedecreased considerably if propersegregation is practiced. "Clean" deckdrainage should be segregated fromsources of contamination. Many sourcesexist on an offshore platform whereleaks or spillages could occur. The areasshould be secured so that all leakagesand/or spills are contained and notdischarged overboard.

Good operation and maintenancepractices reduce waste flows andimprove treatment efficiencies, as wellas reducing the frequency andmagnitude of system upsets. Someexamples of good offshore operationare:

1. Separation of waste crankcase oilsfrom deck drainage collection systems.

2. Minimization of wastewatertreatment system upsets by thecontrolled usage of deck washdowndetergents.

3. Reduction of oil spillage through theuse of good prevention techniques suchas drip pans and other collectionmethods.

4. Elimination of oil drainage frompump bearings and/or seals by directingthe drainage to the crude oil processingsystem.

5. If oil is used as a spotting fluid,careful attention to the operation of thedrilling fluid system could result in thesegregation from the main drilling fluidsystem of the spotting fluid and thedrilling fluid that has been contaminatedby the spotting oil. Once segregated, thecontaminated drilling fluid can bedisposed of in an environmentallyacceptable manner.

Proper initial engineering of thevarious systems is essential to properoperation and ease of maintenance. Theuse of spare equipment is a requirementfor continual operation whenbreakdowns occur. Selection of propertreatment chemicals,to insure optimumpollutant removals, is essential. Alarmsshould be provided to make the operatoraware of off-normal conditions socorrective action can be taken.

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Federal Register / Vol. 50, No. 165 / Monday, August 26, 1985 1 Proposed Rules

Careful planning, good engineeringand a commitment on the part of theoperating, maintenance andmanagement personnel are needed toensure that the full benefits of allpollution reduction facilities arerealized.

The Agency solicits comment onwhether the final regulation shouldinclude best management practices andwhat substantive areas should beaddressed.

XVI. Upset and Bypass Provisions

A recurring issue of concern has beenwhether industry guidelines shouldinclude provisions authorizingnoncompliance with effluent limitationsduring periods of "upset" or "bypass."An upset, sometimes called an"excursion", is an unintentionalnoncompliance occurring for reasonsbeyond the reasonable control of thepermittee. It has been argued that anupset provision is necessary in EPA'seffluent limitations because such upsetswill inevitably occur even in properlyoperated control equipment. Becausetechnology based limitations requireonly what technology can achieve, it isclaimed that liability for such situationsis improper. When confronted with thisissue, courts have disagreed on whetheran explicit upset or excursion exemptionis necessary, or whether upset orexcursion incidents may be handledthrough EPA's exercise of enforcementdiscretion. Compare Marathon Oil Co. v.EPA. 564 F.2d 1253 (9th Cir. 1977) withWeyerhaeuser v. Castle, 590 F.2d 1011(D.C. Cir. 1978), and Corn RefinersAssociation, et al. v. Castle, 594 F.2d1223 (8th Cir., 1979). See also AmericanPetroleum Institute v. EPA, 540 F.2d 1023(loth Cir. 1976); CPC International, Inc.v. Train. 540 F.2d 1320 (8th Cir. 1976);and FMC Corp. v. Train, 539 F.2d 973(4th Cir. 1976).

A bypass is an act of intentionalnoncompliance during which wastetreatment facilities are circumventedbecause of an emergency situation. EPAhas in the past included bypassprovisions in NPDES permits.

The Agency has determined that bothupset and bypass provisions should beincluded in NPDES permits. (See 40 CFR122.41 (in) and (n), published at 48 FR14168, April 1, 1983.) The upset provisionestablishes an upset as an affirmativedefense to prosecution for violation oftechnology-based effluent limitations.The bypass provision authorizesbypassing to prevent loss of life,personal injury, or severe propertydamage. Consequently, permittees in theoffshore segment of this industry will beentitled to upset and bypass provisions

in NPDES permits. Thus, these proposedregulations do not address these issues.

XVI. Variances and Modifications

Upon the promulgation of finalregulations, the effluent limitations forthe appropriate subcategory must beapplied in all Federal and State NPDESpermits thereafter issued to directdischargers in the oil and gas extractionfndustry.

For the BPT effluent limitations, theonly exception to the binding limitationsis EPA's "fundamentally differentfactors" variance. See E.I. duPont deNemours and Co. v. Train, 430 U.S. 112(1977); Weyerhaeuser Co. v. Castle,supra; EPA v. Notional Crushed StoneAssociation, et al. 449 U.S. 64 (1980).This variance recognizes that there maybe factors concerning a particulardischarger that are fundamentallydifferent from the factors considered inthis rulemaking. This variance clausewas originally set forth in EPA's 1973-1976 industry regulations. It is nowincluded in the NPDES regulations andwill not be included in specific industryregulations. See the NPDES regulation,40 CFR 125, Subpart D, 44 FR 32854,32893 (June 7, 1979), 45 FR 33512 (May19, 1980), 46 FR 9460 (January 28, 1981),and 47 FR 52309 (November 19, 1982) forthe text and explanation of the"fundamentally different factors"variance.

Dischargers subject to BAT and BCTlimitations are also eligible for EPA's"fundamentally different factors"variance. In addition, BAT limitationsfor nonconventional pollutants may bemodified under sections 301 (c) and (g)of the Act. Section 301(1) precludes theAdministrator from modifying BATrequirements for any pollutants whichare on the toxic pollutant list undersection 307(a)(1) of the Act.

The economic modification section(301(c)) gives the Administratorauthority to modify BAT requirementsfor nonconventional pollutants fordischargers who file a permitapplication after July 1, 1977, upon ashowing that such modifiedrequirements will: (1) represent themaximum use of technology within theeconomic capability of the owner oroperator; and (2) result in reasonablefurther progress toward the eliminationof the discharge of pollutants.

The environmental modificationsection (301(g)) allows theAdministrator, with the concurrence ofthe State, to modify limitations fornonconventional pollutants from anypoint source upon a showing by theowner or operator of such point sourcesatisfactory to the Administrator that:

(a) Such modified requirements willresult at a minimum in compliance withBPT limitations or any more stringentlimitations necessary to meet waterquality standards;

(b) Such modification will notinterfere with the attainment ormaintenance of that water quality whichshall assure protection of public watersupplies, and the protection andpropagation of a balanced population ofshellfish, fish, and wildlife, and allowrecreational activities, in and on thewater and such modification will notresult in the discharge of pollutants inquantities which may reasonably beanticipated to pose an unacceptable riskto human health or the environmentbecause of bioaccumulation, persistencyin the environment, acute toxicity,chronic toxicity (includingcarcinogenicity, mutagenicity orteratogenicity), or synergisticpropensities.

Section 301(j)(1)(B) of the Act requiresthat application for modifications undersection 301 (c) or (g) must be filed within270 days after the promulgation of anapplicable effluent guideline. For furtherdetails, see 43 FR 40859, September 13,1978.

XVIII. Relationship to NPDES Permits

The effluent limitations in theseregulations will be applied to individualdischargers through NPDES permitsissued by EPA or approved Stateagencies under section 402 of the Act.The preceding section of this preamblediscussed the binding effect of thisregulation on NPDES permits, except tothe extent that variances andmodifications are expressly authorized.This section describes several otheraspects of the interaction of theseregulations with NPDES permits.

One matter that has been subject todifferent judicial views is the scope ofNPDES permit proceedings in theabsence of effluent limitations,guidelines, and standards. Under currentEPA regulations, states and EPA regionsthat issue NPDES permits beforeregulations are promulgated do so on acase-by-case basis on consideration ofthe statutory factors. See US. SteelCorp. v. Train, 556 F.2d 844, 854 (7th Cir.1977.) In these situations, EPAdocuments and draft documents(including these proposed regulationsand supporting documents) are relevantevidence, but are not binding in NPDESpermit proceedings. (See 44 FR 32854,June 7, 1979.)

Another noteworthy topic is the effectof this regulation on the powers ofNPDES permit-issuing authorities. Thepromulgation of this regulation does not

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restrict the power of any permit-issuingauthority to act in any mannerconsistent with law or these or anyother EPA regulations, guidelines, orpolicy. For example, to the extent thatState water quality standards or otherprovisions of State or Federal lawrequire limitation of pollutants notcovered by this regulation (or requiremore stringent limitations on coveredpollutants), such limitations must beapplied by the permit-issuing authority.

One additional topic that warrantsdiscussion is the operation of EPA'sNPDES enforcement program, manyaspects of which have been consideredin developing this regulation. TheAgency wishes to emphasize that,although the Clean Water Act is a strictliability statute, the limitation ofenforcement proceedings by EPA isdiscretionary (Sierra Club v. Train, 527F.2d 485, 5th Cir. 1977). EPA hasexercised and intends to exercise thatdiscretion in a manner that recognizesand promotes good faith complianceefforts and conserves enforcementresources for those who fail to makegood faith efforts to comply with theAct.

XIX. Summary of Public Participation

The Agency has had contact withindividual companies in the industryand with associations such as theOffshore Operators Committee, thePetroleum Equipment SuppliersAssociation, the Western Oil and GasAssociation, the Alaska Oil and GasAssociation, and the AmericanPetroleum Institute during the collectionof information and data basic to thisproposal. Information supplied by thesegroups was used in the development ofthis proposal. The Agency has also metwith or received comments from otherorganizations such as the NaturalResources Defense Council and theSierra Club. The Agency held meetingson BAT permits based upon bestprofessional judgement and to solicitinput from the above groups, the generalpublic, and the states in Denver,Colorado on June,11-12, 1984 and inSanta Barbara, California on July 27-29.1984.XX. Alternative Approaches toRegulation

A. Diesel Oil Recovery

During the drilling of a well, theaddition of oil ("pill") may be requiredto free a stuck drill bit or string. Thetype of oil typically used is diesel oil.This oil, when added, would most likelycause the drilling fluid to exceed effluentlimitations for free oil (sheen) andtoxicity (LC-50), which would make it

unacceptable for discharge. If theportion of the drilling fluid that containsthe diesel oil can be segregated from therest of the drilling fluid system andremoved ("pill" removal or recovery),then it could be disposed of in anenvironmentally acceptable manner.Then the remainder of the spent drillingfluid system has a higher likelihood ofmeeting the free oil and toxicitylimitations and may be acceptable fordischarge.

The volume of drilling wastes thatmust be removed from the drilling fluidsystem to assure recovery of all spottingfluids is yet to be determined. TheAgency is currently developing aninformation collection program toresolve such technical issues. Thisinformation will be considered duringdevelopment of the final regulations,which could result in the allowabledischarge of drilling fluids to whichdiesel oil pills have been added,provided effective pill removal/recoverypractices are implemented. The Agencysolicits comments on this approach tothe regulation of drilling fluids and drillcuttings.

B. Specific Pollutant Approach

The Agency is considering analternate approach to the regulation ofwaste discharges for this industrysegment whereby specific pollutantswould be limited instead of formulationsor compounds. For example, rather thanregulating "diesel oil" as a pollutantparameter, one or more of its toxicpollutant constituents would beregulated. For diesel oil this couldinclude benzene, toluene, ethylbenzene,and naphthalene. The Agency willconsider this approach when reviewingthe comments on the proposedlimitations. Those commenterscriticizing proposed toxicity limitationsor a prohibition on the discharge ofdiesel oil should address the alternativeof specific numeric limitations on thepriority pollutant constituents of drillingfluids and additives.

C. Alternatives for Regulating ProducedWater Discharges

The Agency is evaluating severalalternative approaches to NSPS forproduced water other than, or combinedwith, the water depth basis forreinjection selected for today's proposedregulations.

One alternative approach is to targetzero discharge requirements to thoseplatforms which use biocides or otherchemicals in their produced waterhandling systems, regardless of facilitytype or location. In other words, thosefacilities that use biocides or otherchemicals would be required to meet a

zero discharge standard for producedwater. Another approach would be toregulate the types and discharge levelsof any biocides used as well as otherpollutants added to produced waterwastestreams. This could beaccomplished by meeting a toxicity-based effluent limitation through use ofless toxic biocides, i.e., productsubstitution, or by limiting the quantitiesof biocides or other chemicals used.

The Agency will be performing anextensive survey on the use anddischarge of biocides and otherchemicals in produced water by existingoffshore facilities in order to evaluatethe appropriateness and feasibility ofthis type of approach. This informationwill be considered during developmentof the final regulations. Upon analysis ofthis information, the Agency may selecta final regulatory option for producedwater based upon reinjection forfacilities that use biocides or otherchemicals, product substitution torequire the use of less toxic or persistentbiocides and chemicals, establishingeffluent limitations and standards tolimit the quantities of biocides andchemicals, or an option based on acombination of these three approaches.

The Agency is also evaluating theappropriateness of imposing the zerodischarge requirement for new sourcefacilities located in the Gulf of Mexicoin water depths of less than the 20 meterisobath appearing in today's proposedNSPS regulations. This includesestimating the number, size and type offacilities to be located in such waters,and analysis of differential costs, andamount of pollutants removed comparedto the depth bases of today's NSPSproposal for produced water.

The Agency will be performing atract-by~tract assessment of water depthto obtain NSPS profile and costinginformation in order to properlycharacterize this segment of NSPSoffshore platforms. This information willbe considered during development of thefinal regulations.

D. Oil Content Limitations

The Agency is considering th6establishment of quantitative effluentlimitations and standards on oil content.which would replace either the visiblesheen or static sheen detection methodfor determining compliance with theprohibition on discharges of free oil.Such an alternative limitation couldapply to deck drainage, drilling fluids,drill cuttings, well treatment fluids, andproduced sand waste streams. TheAgency solicits comment on thisalternative.

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XXI. Solicitation of Comments

The Agency invites and encouragescomments on any aspect of theseproposed regulations, but is particularlyinterested in receiving comments on theissues listed below, the alternativeapproaches to regulation discussed inSection XX, and on the "clearinghouse"approach to drilling fluids (NSPS andBAT Option 2). In order for the Agencyto evaluate views expressed bycommenters, the comments shouldcontain specific data and information tosupport their views.

1. The Agency does not have adequateinformation on whether an operator candetermine prior to the commencement ofproduction operations whether biocidesor other chemicals will be requiredduring such production operations. TheAgency is requesting additionalinformation to determine whether anoperator can determine in advance ofdevelopment and production whether itwill need biocides or other chemicals.This information will be used todetermine whether an operator couldplan during design and construction of anew facility for compliance withlimitations and standards based uponbiocide or other chemical usage.

2. The Agency's information onbiocides is based on the registration ofvarious pesticides with EPA's Office ofPesticides. The Agency's approach todetermining which biocides are usedand quantities of use is presented in theEPA report titled Biocides in Use onOffshore Oil and Gas Platforms andRigs. The Agency is solititing additionaldata on the actual use and applicationrates of biocides. In addition, theAgency invites comments andsupporting data on alternatives tobiocides for control of bacteria.

3. The Agency's evaluation, of varioustreatment technologies shows that onlyreinjection of produced water effectivelyreduces priority pollutant dischargesassociated with produced water. Inparticular, EPA concluded that BiPTtechnologies are not effective inreducing priority pollutant levels. TheAgency invites comments on the use ofother treatment technologies that reduceor eliminate priority pollutants inproduced water discharges fromoffshore operations.

4. The Agency's estimate of newsource compliance costs for zerodischarge of produced water in the Gulfof Mexico is based on a projection ofplatforms in depths of 50 feet(approximately 15 meters) andextrapolated to 20 meters. The Agencywill be performing tract-by-tractassessments to determine whether a7ero discharge requirement for water

depths less than the 20 meter isobathwould be more appropriate for the Gulfof Mexico. The Agency will also use thisinformation to refine its cost estimatesfor today's proposed NSPS option forproduced water. The Agency invitesinterested parties to suggest approachesand provide information to perform thisassessment.

5. The Agency has limited informationon the mercury and cadmium content inforeign and domestic sources of barite.The Agency also has limited data on theeffect that blending of different baritesources has on barite metals content.For purposes of its economic analysissupporting today's proposal, the Agencyassumed a fifteen percent increase inthe price of barite to reflect theadditional storage, maintenance,transportation, and monitoring costsassociated with providing offshoreoperations with barite of low toxicmetals content. The Agency invitescomments and supporting data on theavailability of barite with low metalscontent and the priority pollutantcontent of barite.

The Agency also has limitedinformation on the heavy metals contentof drilling mud clays and additives andseeks to determine whether their toxicmetals content warrants regulation on anational basis. The Agency solicitsadditional information on theconcentrations of mercury, cadmium,and other toxic metals in the basicdrilling mud clays, such as bentonite,attapulgite and hematite.

6. The Agency intends to prepare costestimates for the application of add-ontechnologies for the handling andtreatment of produced water, drillingfluids, drill cuttings and deck drainagewaste streams from existing offshore oiland gas facilities. In the performance ofthis work, an important element will beretrofit costs to install new equipmenton existing platforms. These costs wouldinclude platform addition costs,auxiliary platform costs and equipmentrearrangement costs. The Agencysolicits such costs, including geographiccost multipliers for use in preparing theestimates. Comments received on thesubject should be in a form usable forthe intended purpose, with appropriatereferences to substantiate their bases.

7. The proposed NSPS regulation forproduced water is, in part, based onimproved operation of BPT treatment toachieve oil and grease levels in theproduced water discharge which arelower than BPT levels. The Agencybelieves that incremental costs beyondBPT to achieve a 59 mg/l maximum oiland grease standard will be minimal butsome costs will be realized. The Agencysolicits comments on the cost

differential to meet the lower oil andgrease level, realizing, however, thatnew sources will not incur retrofitexpenses. These costs could include thecost of increased chemical use and moreoperator labor.

8. In the preparation of capital costestimates, the Agency used variousgeographic and location cost multipliersto determine installed equipment costsand to adjust the base costs of facilities(which were prepared for the Gulf ofMexico) to other geographic locations.These other locations are: AtlanticCoast, California Coast, Cook Inlet/Shelikof Strait, Norton Basin, Gulf ofAlaska, and the Beaufort Sea. TheAgency solicits comments on theaccuracy of the factors used, which arepresented in Section XII A. of thispreamble.

9. During the data gathering programsfor the development of today's proposedregulations, the Agency was unable toobtain sufficient information on the oilcontent of drill cuttings before and afterapplication of cuttings washertechnology with which to establishnational effluent limitations. Whilesome information was available, theAgency does-not believe that the database is complete enough to be used forthe formulation of national regulations.Therefore, the Agency solicitscomments, including empirical data, onthe oil content of drill cuttings beforeand after washing. This includes waterwash, solvent cleaning and thermalprocessing technologies. Thisinformation is solicited for the use ofboth diesel oil and mineral oil aslubricity agents or spotting fluids for thedrilling of offshore oil and gas wells. Inaddition, the Agency is considering andsolicits comments on theappropriatenesh of establishing effluentlimitations on oil content for drillcuttings in addition to the limitations onfree oil, diesel oil and oil-based drillingfluids in the proposed options for NSPSand BAT.

10. The Agency is aware that at leasttwo other processes exist for thetreatment and disposal of drilling fluids,namely detoxification and solidification.These are relatively new technologiesand, as such, were not considered by theAgency for this proposed rulemaking.The Agency solicits comments on theapplicability of these two technologiesfor the offshore subcategory, and seeksinformation on cost, energy andnonwater quality aspects of using thesetechniques to process and dispose ofdrilling fluid waste streams.

11. The Agency requests comment onall aspects of the static sheen test aspresented in Appendix 1 of today's

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proposed regulations. The Agencyparticularly invites comment on thesample volumes, method of observationfor sheen, and precision (reproducibility)of the proposed method.

12. The Agency requests comment onall aspects of the diesel oil analyticalmethod as presented in Appendix 2 oftoday's proposed regulations for use ondrilling fluids and drill cuttings wastestreams.

13. The Agency requests comment onthe appropriateness of establishing alimitation or standard on oil and greasefor deck drainage in addition to, orinstead of, a prohibition on thedischarge of free oil.

XXII. Executive Order 12291

Executive Order 12291 requires EPAand other agencies to perform regulatoryimpact analyses of major regulations.The primary purpose of the ExecutiveOrder is to ensure that regulatoryagencies carefully evaluate the need fortaking the regulatory action. Major rulesare those which impose a cost on theeconomy of $100 million a year or moreor have certain other economic impacts.This regulation is not a major regulationbecause its annualized cost of $91.5million [1983 dollars) is less tharl $100million and it meets none of the othercriteria specified in paragraph (b) ofExecutive Order 12291.

XXIII. Regulatory Flexibility Analysis

Pub. L. 96-354 requires EPA to preparean Initial Regulatory Flexibility Analysisfor all proposed regulations that have asignificant impact on a substantialnumber of small entities. This analysismay be done in conjunction with or aspart of any other analysis conducted bythe Agency. The economic impactanalysis described above indicates thatthere will not be a significant impact onany segment of the regulated population.Additionally, the analysis hasdetermined that none of the oil and gasdevelopment companies directlyaffected by the regulation are smallbusinesses. Therefore, a formalregulatory flexibility analysis is notrequired.

XXIV. OMB Review

This regulation was submitted to theOffice of Management and Budget forreview as required by Executive Order12291. Any written comments from OMBto EPA and any EPA responses to thosecomments are available for publicinspection at Room M2404, U.S. EPA,401 M Street, S.W., Washington, D.C.20460 from 9:00 a.m. to 4:00 p.m. Mondaythrough Friday, excluding Federalholidays.

XXV. List of Subjects in 40 CFR Part 435

Oil and gas extraction, Wastetreatment and disposal, Water pollutioncontrol.

XXVI. Appendices

Appendix A-Abbreviations, Acronyms, andOther Terms Used in this Notice

Act-The Clean Water Act.Agency-The U.S. Environmental

Protection Agency.API-American Petroleum Institute.BAT-The best available technology

economically achievable, under Section304(b)(2)(B) of the Act.

BCT-The best conventional pollutantcontrol technology.

BDT-The best available demonstratedcontrol technology processes, operatingmethods, or other alternatives, includingwhere practicable, a standard permitting nodischarge of pollutants under Section306(a)(1) of the Act.

BMP-Best management practices underSection 304(e) of the Act.

BOD-Biochemical oxygen demand.BPT-The best practicable control

technology currently available, under Section304(b)(1) of the Act.

Bypass-An act of intentionalnoncompliance during which waste treatmentfacilities are circumvented becatise 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 (Pub. L. 95-217).

COD-Chemical oxygen demand.Direct discharger-A facility which

discharges or may discharge pollutants towaters of the United States.

LC-50--The concentration of a testmaterial that is lethal to 50 percent of the testorganisms in a bioassay.

NPDES Permit-A 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.

OOC--Offshore Operators Committee.PESA-Petroleum Equipment Suppliers

Association.Priority Pollutants-The 65 pollutants and

classes of pollutants declatred toxic underSection 307(a) of the Act. Appendix Ccontains a listing of specific elements andcompounds.

RCRA-Resource Conservation andRecovery Act (Pub. L. 94-580) of 1976.Amendments to Solid Waste Disposal Act.

SPCC-A spill prevention control andcountermeasure plan required under Section311(j) of the Act.

Spot-The introduction of oil to a drillingfluid system for the purpose of freeing a stuckdrill bit or string.

TOC-Total organic carbon.Upset-An unintentional noncompliance

occurring for reasons beyond the reasonablecontrol of the permittee.

WOGA-Western Oil and GasAssociation.

Appendix B-Generic Drilling Fluids List

Type of fluid and base components

1. Potassium/Polymer Mud:Barite .....................................................................Caustic soda .........................................................Cellulose polym er ................ e...............................Drilled solids ..........................................................Potassium chloride .............Seawater or fresh water ......................................Starch .. ............. ...............................................Xanthan gum polymer ..........................................

2. Seawater/Lignosullonate Mud:Attapulgite or bentonite ......................................

an Ite ............ . . ...............Caustic soda ..........................................................Cellulose polymer .............................................Drilled solids ...................................Lignite ................ ...............Lignosulfonate .......................................................Seawater ................................................................Soda ash/sodium bicarbonate ............................

3. Lime Mud:Barite .....................................................................Bontonite ............................................................Caustic soda ......................................................Drilled solids .....................................................Fresh water or seawater ...............................Lignite ............... . ...............Ugnosulfonate .....................................................Lim e ..................................................................Soda ash/sodium bicarbonate ............................

4 Nondispersed Mud:Acrylic polymer .....................................................Barite .....................................................................Bentonite ............... ...............Drilled solids .........................................................Fresh water or seawater .....................................

5 Spud Mud (slugged intermittently with sea-water):

Attapulgite or bentonite ......................................Barite ......................................................................Caustic soda ....................Lime ............ ............................Seawater ................................................................Soda ash/sodium bicarbonate ............................

6. Seawater/Fresh Water Gel Mud:Attapulgite or bentonite .....................................Barite ............. . . ..............Caustic sed a ........................................................Cellulose polymer .................................................Drilled solids .........................................................Lime ......................................................................Seawater or fresh water ......................................Soda ash/sodium bicarbonate ............................

7. Lightly Treated Lignosulfonate Freshwater/Seawater Mud:Barite ......................................................................Bentonite ................... .. .................Caustic soda ..........................................................Cellulose polym er .............................................Drilled solids .........................................................Lignite . ....................Lignosultonate .......................................... .....Lime ........................................................................Seawater.to-freshwater ratio ...............................Soda ash/sodium bicarbonate .......................

8. Lignosulfonate Freshwater Mud:Brite .................................................. ..............Bentonite ..............................................................Caustic soda ..........................................................Cellulose polym er .................................................Drilled solids ..........................................................Fresh water ...........................................................Lignite .................................................................Lignosulfonate ......................................................Lime ................ ...................

'As needed.2 1:1 approximately.

Appendix C-126 Priority PollutantsAcenaphtheneAcroleinAcrylonitrileBenzeneBenzidine

Typicalconcentrationrange

(poundper

barre!)

0-4500.5-3

0.25-520-100

5-50(1)

2-120.25-2

10-5025-4501-5

0.25-520-100

1-102-15

(1)0-2

25-18010-501-5

20-100(,)0-102-152-200-2

05-225-180

5-1520-70(1)

10-50O-500-2

0.5-1(1)0-2

10-500-5o

0.5-30-2

20-1000-2

(1)0-2

0-18010-50

1--30-2

20-1000-42-60-2

(1)0-2

0-45010-502-50-2

20-100(1)2-104-150-2

3462334623

~4C21 Federal Register / Vol. 50, No. 165 I Monday, August 26, 1985 / ProposedRulesharbon tetrechloride (tetrachloromethane)

( lorobenzene1.2,4-trichlorobenzeneI lexachlorobenzene1,2-dichloroethane1,1,1-trichloroethaneI :exachlorocthane1,1-dichloroethane1,1,2-trichloroelhane1,1,2,2-tetrachloroethaneChloroethaneBis[2-chloroethyl) ether2-chloroethyl vinyl ether (mixed)2-chloronaphthalerne2,4,6-trichlorophenolParachlorometa cresolChloroform (trichloromethane)2-chlorophenol1.2-dichlorobenzeneI ,3-dichlorobenzene1,4-dichlorobenzene3,3-dichlorobenzidine1,1-dichloroethylene1,2-trans-dichloroethylene2,4-dichlorophenol1,2-dichloropropane1,2-dichloropropylene (1,3-dichloropropene)2,4-dimethylphenol2,4-dinitrotoluene2,6-dinitrotoluene1,2-diphenylhydrazineEthylbenzeneFluoranthene4-chlorophenyl phenyl ether4-bromophenyl phenyl etherBis(2-chloroisopropyl) etherBis(2-chloroethoxy) methaneMethylene chloride(dichloromethane)Methyl chloride (dichloromethane)Methyl bromide (bromomethane)Bromoform (Itibromomethane)DichlorobromomethaneChlorodibromomethaneHexachlorobutadieneHexachlorocyclopentadieneIsophoroneNaphthaleneNitrobenzene2-nitrophenol4-nitrophenol2,4-dinitrophenol4,6-dinitro-o-cresolN-nitrosodimethylamineN-nitrosodiphenylamineN-nitrosodi-n-propylaminePentachlorophenolPhenolBis(2-ethylhexyl)phthalateButyl benzyl phthalateDi-N-Butyl PhthalateDi-n-Octyl phthalateDiethyl PhthalateDimethyl phthalate1,2-benzanthracene (benzo(a)anthracene)Benzo(a)pyrene (3,4-benzo-pyrene)3,4-Bcnzofluoranthene(benzo(b)fluoranthene)11,12-

benzofluoranthene(benzo(b)fluoranthene)ChryseneAcenaphthyleneAnthracene1,12-benzoperylene(benzo(ghi)perylene)FluorenePhenanthrene1,2,5,6-

dibenzanthracene(dibenzo(h)a nthracene)

Indeno(1,2,3-cd)pyrene(2,3-o-phenylenepyrene)

PyreneTetrachioroethyleneTolueneTrichloroethyleneVinyl chloride (chloroothylene}AidrinDieldrinChlordane (technical mixture and

metabolites)4,4-DDT4,4-DDE(p,p-DDX)4,4-DDD(p,p-TDE)Alpha-endosulfanBeta-endosulfanEndosulfan sulfateEndrinEndrin aldehydeHeptachlorHeptachlor epoxide (BHC-

hexachlorocyclohexane)Alpha-BHCBeta-BHCGamma-BHC(lindane)Delta-BHC(PCB-polychlorinated biphenyls}PCB-1242(Arochlor 1242)PCB-1254(Arochlor 1254)PCB-1221(Arochlor 1221)PCB-1232(Arochlor 1232)PCB-1248(Arochlor 1248)PCB-1260Arochlor 1260)PCB-1016(Arochlor 1016)ToxapheneAntimonyArsenicAsbestosBerylliumCadmiumChromiumCopperCyanide, TotalLeadMercuryNiokelSeleniumSilverThalliumZinc2,3,7,8-tetrachloro-dibenzo-p-dioxin (TCDD)

Appendix D-Major Documents Supportingthe Proposed Regulation

With the exception of the first documentlisted in each of the following subsections, alldocuments are available only for publicinspection and copying at Room 2404, U.S.EPA, 401 M St., S.W., Washington, D.C. from9:00 am to 4:00 pm Monday through Friday,excluding Federal holidays. The firstdocument listed in each section may beobtained by contacting the individuals listedin the Addresses section of this preamble.

Technology and Cost Reports

1. Development Document for ProposedEffluent Limitations Guidelines and NewSource Performance Standards for theOffshore Segment of the Oil and GasExtraction Point Source Category, EPA 440/1-85/0556.

2. Assessment of Existing Data for theOffshore Oil and Gas Extraction Industry,October 6, 1980.

3. Technical Feasibility of Brine Reinjectionfor the Offshore Oil and Gas ExtractionIndustry, May, 1981.

4. Sampling and Logistics Plan for EPAPriority Pollutant Sampling Program, OffshoreOil and Gas Extraction Industry, October 5,1981.

5. Evaluation of Analytical Data Obtainedfrom the Gulf of Mexico Sampling Program,Offshore Oil and Gas Extraction Industry,Volumes I and II, February 4, 1983.

6. Review of Drill Cuttings WasherSystems, Offshore Oil and Gas ExtractionIndustry, October 14, 1983.

7. Technologies for the Onshore Treatmentof Produced Waters from Offshore Oil andGas Platforms, December, 1983.

8. Results of Laboratory Analyses onDrilling Fluids and Cuttings, April 3, 1984.

9. Acute Toxicity of Eight Laboratory-Prepared Generic Drilling Fluids to Mysids,May, 1984.

10. Acute Toxicity of Suspended ParticulatePhase of Drilling Fluids Containing DieselFuels, May, 1984.

11. Results of the Drilling Fluids ResearchProgram Sponsored by EPA's Gulf BreezeEnvironmental Research Laboratory, 1976-1984, and Their Application to HazardAssessment, EPA--600/4-84-055, June, 1984.

12. Summary of Cost Estimates for Systemsto Treat Produced Water Discharges in theOffshore Oil and Gas Industry to Meet BATand NSPS, June 28, 1984.

13. Application of the Proposed BestConventional Pollutant Control Technology(BCT) Cost Tests on Produced Water-Offshore Oil and Gas Extraction Industry,June 28, 1984.

14. Cost of Offshore Cuttings WasherSystems, Offshore Oil and Gas ExtractionIndustry, September 12, 1983, revised June,

J,984.15. Technical Memorandum: Costs of Drill

Cuttings Washing and Mud and CuttingsTransportation to Shore and Land Disposalfor the Offshore Oil and Gas Industry-Gulfof Mexico, April 1984, revised July 5, 1984.

Environmental Reports

1. Assessment of Environmental Fate andEffects of Discharges From Offshore Oil andGas Operations, 1984, EPA 440/4-85/002.

2. Analysis of Drilling Muds from 74Offshore Oil and Gas Wells in the Gulf ofMexico, 1984.

3. Biocides in Use on Offshore Oil and GasPlatforms and Rigs, 1984.

4. 403(c) Determination for Lease Sale No.52: Background Review, 1984.

Economic Reports

1. Economic Impact Analysis of P-oposedEffluent Guidelines and Standards for theOffshore Oil and Gas Industry, EPA 440/2-85/003, 1984.

2. Cost Effectiveness Analysis of ProposedEffluent Guidelines and Regulations for theOffshore Oil and Gas Industry, 1984.

3. Economic Impacts Analysis of theOffshore Effluent Guideline Affecting theBarite Industry, 1984

26, 1985 / Proposed Rules....

-- rFederal Register / Vol. 50, No. 165 / Monday, August


Dated: August 2, 1985.Lee M. Thomas,Administrator.

For the reasons discussed above, EPAproposes to revise 40 CFR Part 435 asfollows:

PART 435-OIL AND GASEXTRACTION POINT SOURCECATEGORY

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).

Appendix 1-Static Sheen TestAppendix 2-Analysis of Diesel Oil in

Drilling Fluids and Drill CuttingsAppendix 3-Drilling Fluids Toxicity TestAppendix 4-Regulatory Boundaries

Authority: Secs 301, 304 (b), (c), (e), and (g),306 (b) and (c), 307 (b) and (c), and 501,Federal Water Pollution Control Act asamended (the Act): 33 U.S.C. 1251, 1311, 1314(b), (c), (e), and (g), 1316 (b) and (c), 1317 (b)and (c), 1318 and 1361; 86 Stat. 816, Pub. L.92-500; 91 Stat. 1567, Pub. L. 95-217.

Subpart A-Offshore Subcategory

§ 435.10 Applicability; 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 ofthe Act. This includes offshore facilitiesthat transport wastes to onshorelocations for treatment or disposal.

§ 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 to

counterbalance 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 drillingfluid has diesel, crude, or some other oilas its continuous phase with water asthe dispersed phase.

(c) The term "spent drilling fluidsystem discharge" shall mean the bulkdischarge of an entire drilling fluidsystem prior to a complete changeoverto another drilling fluid system, or at thecompletion of the drilling of a well.

(d) The term "drill cuttings" shall referto the particles generated by drilling intosubsurface geologic formations andcarried to the surface with the drillingfluid.

(e) The term "deck drainage" shallrefer to any waste resulting from deckwashings, spillage, rainwater, and runofffrom gutters and drains including drippans and work areas within facilitiessubject to this subpart.

(f) The term "produced water" shallrefer to the water (brine) brought upfrom the hydrocarbon-bearing strataduring the extraction of oil and gas, andcan include formation water, injectionwater, and any chemicals addeddownhole or during the oil/waterseparation process.

(g) The term "produced sand" shallrefer to slurried particles used inhydraulic fracturing and theaccumulated formation sands and scalesparticles generated during production.

(h) The term "well treatment fluids"shall refer to those fluids used instimulating a hydro.carbon-bearingformation or in completing a well for oiland gas production, and drilling fluidsused in reworking a well to increase orrestore productivity.

(i) The term "sanitary waste" shallrefer to human body waste dischargedfrom toilets and urinals located withinfacilities subject to this subpart.

(j) The term "domestic waste" shallrefer to materials discharged from sinks,showers, laundries, and galleys locatedwithin facilities subject to this subpart.

(k) The term "M10" shall mean thoseoffshore facilities continuously mannedby ten (10) or more persons.

(1) The term "M9IM" shall mean thoseoffshore facilities continuously mannedby nine (9) or fewer persons or onlyintermittently manned by any number ofpersons.

(m) The term "no discharge of free oil"shall mean that waste streams may notbe discharged when they would cause afilm or sheen upon or a discoloration ofthe surface of the receiving water, asdetermined by the Static Sheen Test.

(n) The term "Static Sheen Test" shallrefer to the standard test procedure thathas been developed for this industrialsubcategory for the purpose ofdemonstrating compliance with therequiremnent of no discharge of free oil.The methodology for performing theStatic Sheen Test is presented inAppendix 1 of this regulation.

(o) The term "Analysis of Diesel Oil inDrilling Fluids and Drill Cuttings" shallrefer to the standard test procedure thathas been developed for this industrialsubcategory for the purpose ofdetermining the presence of diesel oil indrilling fluids and drill cuttings. Themethodology for performing this test ispresented in Appendix 2 of thisregulation.

(p) the term "diesel oil" shall refer tothe grade of distillate fuel oil, asspecified in the American Society forTesting and Materials' StandardSpecification D975--81, that is typicallyused as the continuous phase inconventional oil-based drilling fluids.

(q) The term "Drilling Fluids ToxicityTest" shall refer to the standardbioassay test procedure that has beendeveloped for this industrialsubcategory for the purpose ofmeasuring the toxicity of drilling fluids.The methodology for performing theDrilling Fluids Toxicity Test is presentedin Appendix 3 of this regulation.

(r) The term "96-hr LC-50" shall meanthe concentration of test material that islethal to 50 percent of a the testorganisms in a bioassay after 96 hoursof constant exposure.

(s) The term "exploration facility"shall mean any fixed or mobile structuresubject to this subpart that is engaged inthe drilling of wells to determine thenature of potential hydrocarbonreservoirs.

(t) The term "development facility"shall mean any fixed or mobile structuresubject to this subpart that is engaged inthe drilling and completion of productivewells.

(u) The term "production facility"shall mean any platform or fixedstructure subject to this subpart that isused for active recovery ofhydrocarbons from producingformations.

(v) The term "new source" means anyexploratory, development or productionfacility or activity that meets thedefinition of "new source" under 40 CFR§ 122.2 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 in40 CFR § 122.29(b)(1)(i) shall mean thewater area and ocean floor beneath any

3462534625


exploratory, development, or productionfacility where such facility is conductingits exploratory, development orproduction activities.

(2) The term "significant sitepreparation work" shall mean theprocess of surveying, clearing andpreparing an area of the ocean floor forthe purpose of constructing or placing adevelopment or production facility on orover the site.

(w) The term "gas well" shall refer toany well that produces more than 15,000cubic feet of natural gas for each barrelof produced petroleum liquids.

(x) The term "oil well" shall refer toany well that produces 15,000 cubic feetor less of natural gas for each barrel ofproduced petroleum liquids.

(y) The term "gas development andproduction facilities" shall mean thosefacilities subject to this subpart that areengaged in the development of orproduction from gas wells only.

(z) 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.

(aa) 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.

(bb) The term "maximum" as appliedto BAT effluent limitations for drillingfluids and to NSPS for produced water'and drilling fluids shall mean themaximum concentration allowed asmeasured in any single sample of thedischarged waste stream.

(cc) The term "minimum" as appiiedto BAT effluent limitations and NSPS fordrilling fluids shall mean the minimum96-hour LC-50 value allowed asmeasured in any single sample of thedischarged waste stream.§ 435.12 Effluent limitations guidelinesrepresenting the degree of effluentreduction attainable by the application ofthe best practicable control technologycurrently avail;able (BPT).

Except as provided in 40 CFR 125.30-32, any existing point source subject tothis subpart must achieve the followingeffluent limitations representing thedegree of effluent reduction attainableby the application of the bestpracticable control technology currentlyavailable:

BPT Effluent Limitations

Oil and grease, mg/I

Pollutant Average of Res!dualparameter waste daily v3lues chlorine,

source Maximum for 30 mg/l.for any 1I consecutive Minimum for

day days shall any I daynot

exceed-

Produced waterDeck drainage.Drilling fluids.Drill cuttings.Well treatment

fluids ..................Sanitary.

M10 ...................M9IM ' ..............

Domestic' .............

48(')

(I)(,)

I,)

NANANA

'No discharge of free oil.'Minimum of 1 mg/I and maintained as close to this

concentration as possible.'There shall be no floating solids as a result of the

discharge of these wastes.NA-Not applicable.

§ 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 125.30-32, any existing point source subject tothis subpart must achieve the followingeffluent limitations representing thedegree of effluent reduction attainableby the application of the best availabletechnology economically achievable(BAT):

BAT EFFLUENT LIMITATIONS

Wastesource

Producedwater.

Deckdraiage.

Drilling fluids..

Drill cuttings..

SanitaryM10.

SanitaryM91M.

Domesticwaste.

Producedsand.

Welltreatmentfluids.

Pollutantparameter

orcharact ens-

fie

3AT effluent limitations

[Reserved] ... (Reserved]

Fr-e o I. No d:scharge.

[All othr I

Frec oil ...........Oil-based

fluid.Diesel oil.

Toxicity ...........

Cadmium.

Mercury ..........

Free oil ...........Oil-based

fluid.Diesel oil.

None .............

ollutant pararetcrs reso ,-,vd]

No dischage.No discharge.

No discharge in detectiubeamounts.

Minimum 96-hr LC 50 of thediluted suspended parl:cu-It'o piase (SPP) of the ditll-rig liud shall be 3 0 pccentby voluMp.

I mg/kg dry weight maximumIn the whole drlling fluid.

I mg/kg dry weight maximumin the whole drilling fluid.

No discharge.No discharge.

No discharge in detectableamounts.

None .............. ........ ..

None ...........................

Free oil ........... No dischprge

(All other pollutant parameters reserved].Free oil .......... No discharge.

BAT EFFLUENT LIMITATIONS-Continued

Pollutant "Waste parameterWste hore BAT effluent limitationssource characteris-

tic

[All other pollutant parameters reserved].

§ 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 125,30-32, any existing point source subject tothis subpart must achieve the followingeffluent limitations representing thedegree of effluent reduction attainableby the application of the bestconventional pollutant controltechnology (BCT):

BdT EFFLUENT LIMITATIONS

BCT effluent limitations

Average ofWaste Pollutant daily valuessource parameter or Maximum for 30

characteristic for any 1 consecutiveday days shall

notexceed-

Producedwater.

Oil and grease .... 72 mg/I.

Deck Free Oil ................ Nodrainage. I discharge.

(All other pollutantparameters reserved].

Drilling fluids.,J Free oil ................ NoII discharge.

[All other pollutantparameters reserved].

Drilling Free oil ................ Nocuttings. disch arge.

[All other pollutantparameters eserved].

Sanitary Residual Minimum ofM10. Chlorine. I mg/l

andmain-tained asclose tothisconcentra-.tion aspossible.

Sanitary Floating solids. NoM91M. discharge.

Domestic Floating solids.... Nowato. discharge.

Produced Free oil ................ Nosand. discharge.

[All other pollutantparameters reserved].

Well Free oil ................ Noitreatnvent discharge.

fluids.(All other pollutant

parameters reserved].

For the control of fecal coliform.

48 m0/I.

§ 435.15 Standards of performance fornew sources (NSPS).

Any new source subject to thissubpart must achieve the following newsource performance standards (NSPS):

34626


(a) For all oil development andproduction facilities located in ordischarging to water depth of 20 metersor less in the Gulf of Mexico, AtlanticCoast, and Norton Basin; waterdepth of50 meters or less in the California Coast,Cook Inlet/Shelikof Strait, the AleutianIsland-Chain including Bristol Bay andGulf of Alaska; and water dept of 10meters or less in the Beaufort Sea asspecified in Appendix 4 (RegulatoryBoundaries):

NSPS EFFLUENT LIMITATIONS

Wastesource

Producedwater.

Deckdrainage.

Drilling fluids.

Drll cuttings

SanitaryM10

SanitaryM91M.

Domesticwaste.

Producedsand

treatmentfluids.

Pollutantparameter

orcharacteris-

tic

NSPS effluent limitations

......................... No discharge.'

Free oil . No discharge.

(All other pollutant parameters reserved]

Free oil ........... No discharge.Oil-based No discharge.

fluid.Diesel oil . No discharge in detectable

amounts.Toxicity . Minimum 96-hr LC-50 of th

diluted suspended particulate phase (SPP) of the drilling fluid shall be 3.0 percenby volume.

Cadmium I mg/kg dry weight maximunin the whole drilling fluid

Mercury .......... 1 mg/kg dry weight maximunin the whole drilling fluid

Free oil ........... No discharge.Oil-based No discharge.

fluid.Diesel oil . No discharge in detectabi

amounts.Residual Minimum of 1 mg/I and main

chlorine. tained as close to this concentration as possible.

Floating No Discharge.solids.

Floating No dischargesolids.Free oil ........... No discharge.

(All other pollutant parameters reserved]

Free oil .......... No discharge.

[All other pollutant parameters reserved].

Facilities must be in compliance with the no dischargestancard no later than 300 days after commencement ofdevelopment drilling operations. Prior to that date, dischargesshall comply with the oil and grease standard of 59 mg/Imaximum in § 435.15(b).

(b) For all exploratory facilities andall gas development and productionfacilities regardless of location, and forall oil development and productionfacilities located in and discharging towater depth of more than 20 meters inthe Gulf of Mexico, Atlantic Coast andNorton Basin; water depth of more than50 meters in the California Coast, CookInlet/Shelikof Strait, the Aleutian IslandChain including Bristol Bay and Gulf ofAlaska; and water depth of more than 10meters in the Beaufort Sea as specifiedin Appendix 4 (Regulatory Boundaries):

NSPS EFFLUENT LIMITATIONS

PollutantWaste parameterWsoe or NSPS effluent limitationssource characteris-

tic

Produced Oil and 59 mg/I maximum,Water. grease.

Deck Free oil ........... No discharge.drainage.

[All oter pollutants-Reserved].Drilling fluids.. Free oil ........... No discharge.

Oil-based No discharge.fluid.

Diesel oil. No discharge in detectableamounts.

Toxicity ........... Minimum 96-hr LC-50 of thediluted suspended particu-late phase (SPP) of the drill-ing fluid shall be 3.0 percentby volume.

Cadmium . 1 mg/kg dry weight maximumin the whole drilling fluid.

Mercury .......... I mg/kg dry weight maximumin the whole drilling fluid.

Drill cuttings.. Free oil ........... No discharge.Oil-based No discharge.

fluid.Diesel oil . No discharge in detectable

amounts.Sanitary Residual Minimum of 1 mg/I and main-

M10. chlorine. tained as close to this con-centration as possible.

Sanitary Flosting No Discharge.M91M. solids.

Domestic Floating No discharge,waste, solids.

Produced Free oil ........... No discharge.sand.

(All other iollulant parameters reserved].Well Free oil ........... No discharge.

treatmentfluids.

fAd other pollutant parameters reserved].

Appendix 1-Static Sheen Test

1. Scope and Application

This method is to be used as a compliancetest for the "no discharge of free oil"requirement for discharges of drilling fluids,drill cuttings, deck drainage, produced sand,and well treatment fluids. Free oil refers toany oil contained in a waste stream thatwhen discharged will cause a film or sheenupon or a discoloration of the surface of thereceiving water.

2. Summary of MethodSamples of drilling fluids, deck drainage or

well treatment fluids (0.15 mL and 15 mL) andsamples of drill cuttings or produced sand(1.5 g and 15 g, wet weight basis) areintroduced into ambient seawater in acontainer having an air to liquid interfacearea of 1000 cm . Samples are dispersedwithin the container and observations madeno more than 1 hour later to ascertain if thesematerials cause a sheen, iridescence, gloss, orincreased reflectance on the sUrface of thetest seawater. The occurence of any of thesevisual observations will constitute ademonstration that the tested materialcontains "free oil", and therefore, results in aprohibition on its discharge into receivingwaters.

3. InterferencesResidual "free oil" adhering to sampling

containers, the magnetic stirring bar used tomix drilling fluids, and the stainless steelspatula used to mix drill cuttings will be theprincipal sources of contamination problems.

These problems should only occur ifimproperly washed and cleaned equipmentare used for the test. The use of disposableequipment minimizes the potential for similarcontamination from pipets and the testcontainer.

4. Apparatus Materials and Reagents

4.1 Apparatus.4.1.1 Sampling containers-1 liter

polyethylene beakers.4.1.2 Graduated cylinder-100 mL

graduated cylinder required only foroperations where predilution of muddischarges is required.

4.1.3 Plastic disposable weighing boats.4.1.4 Triple beam scale.4.1.5 Disposable pipets-1 mL and 25 mL

disposable pipets.4.1.6 Magnetic stirrer and stirring bar.4.1.7 Stainless steel spatula.4.1.8 Test container-open plastic

container whose internal cross-sectionparallel to its opening has an area of 1000:±-50cm 2 , and a depth of no more than 30 cm.

4.2 Materials and Reagents.4.2.1 Plastic liners for the test container-

Oil free, heavy duty plastic trash can linersthat do not inhibit the spreading of an oilfilm. Liners must be of a sufficient size tocompletely cover the interior surface of thetest container. Permittees must determine anappropriate local source of liners that do notinhibit the spreading of 0.05 mL diesel fueladded to the lined test container under thetest conditions and protocol described below.

4.2.2 Ambient receiving water.

5. Calibration

None currently specified.

6. Quality Control Procedures

None currently specified.

7. Sample Collection and Handling

7.1 Sampling containers must bethoroughly washed with detergent, rinsed aminimum of 3 times with fresh water, andallowed to air dry before samples arecollected.

7.2 Samples of drilling fluid must beobtained once per day from the active mudpit; the sample volume should range between200 mL and 500 mL.

7.3 Samples of drill cuttings or producedsand must be obtained from each type ofsolids control equipment from whichdischarges occur on any given day prior toaddition of any washdown water; samplesshould range between 200 and 500 grams.

7.4 Samples of deck drainage or welltreatment fluids must be obtained fromholding facility prior to discharge; the samplevolume should range between 200 mL and 500mL.

7.5 Samples must be tested no later than 1hour after collection.

7.6 Drilling fluid samples must be mixedin their sampling containers for 5 minutesprior to testing using a magnetic bar stirrer. Ifpredilution is imposed as a permit condition,the sample must be mixed at the same ratiowith the same prediluting water as thedischarged muds and stirred for 5 minutes.

7.7 Drill cuttings must be stirred and wellmixed by hand in their sampling containers

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e

34628 Federal Register / Vol. 50, No. 165 / Monday, August 26, 1985 / Proposed Rules

prior to testing, using a stainless steelspatula.

8. Procedure

8.1 Ambient receiving water must be usedas the "receiving water" in the test. The testcontainer must have an air to liquid interfacearea of 1000±h50 cm-. The surface of thewater should be no more than 5 cm below thetop of the test container.

8.2 Plastic liners shall be used, one percontainer per test, and discarded afterwards.Some liners may inhibit spreading of addedoil; operators shall determine an appropriatelocal source of liners that do not inhibit thespreading of the oil film.

8.3 Drilling fluid materials, well treatmentfluids, or deck drainage must be introducedinto the test container I cm below the watersurface, by pipet, at 0.15 mL and 15 mL. Pipetsmust be filled and discharged with testmaterial prior to the transfer of test materialand its introduction into test containers. Thetest water-test material mixture must bestirred using the pipet to distribute the testmaterial homogenously throughout the testwater. The pipet must be used only once for atest and then discarded.

8.4 Drill cuttings or produced sand shouldbe weighed on plastic weighing boats; 1.5gram and 15 gram samples must betransferred by scraping test material into thetest water with a stainless steel spatula. Theweighing boat must be immersed in the testwater and scraped with the spatula totransfer any residual material to the testcontainer. The test material must be stirredwith the spatula to an even distribution ofsolids on the bottom of the test container.

8.5 Observations must be made no laterthan 1 hour after the test material istransferred to the test container. Viewingpoints above the test container should bemade from at least three sides of the testcontainer, at viewing angles of approximately60* and 30" from the horizontal. Illuminationof the test container must be representativeof adequate lighting for a workingenvironment to conduct routine laboratoryprocedures.

8.6 Detection of a "silvery"' or "metallic"sheen, gloss, or increased reflectivity; visualcolor; or iridescence on the water surfaceshall constitute a demonstration of "free oil."These visual observations include patchcs,sheets, or streaks of such altered surfacecharacteristics.

Appendix 2-Analysis of Diesel Oil inDrilling Fluids and Drill Cuttings

1. Scope and Application

This method is to be used as a compliancetest for detecting the presence of diesel oil indrilling fluids and drill cuttings wastestreams. The method involves the separationof diesel fuel from drilling fluid or drillcuttings samples and subsequent qualitativeand quantitative analysis by capillary columngas chromatography. The method makes noattempt to chemically identify the individualdiesel components but uses a patternrecognition technique for data analysis.

2. Summary of Method

A weighed amount of drilling fluid or drillcuttings is placed in a retort apparatus and

distilled according to the retortmanufacturer's instructions. The distillate isextracted with methylene chloride, aninternal standard is added, and a GCanalysis is conducted. Using low attenuationfor high sensitivity, a detection of I mg/kg ofdiesel oil in the sample is possible with thismethod.

The analyst is cautioned that there is nostandard diesel fuel oil. The components, asseen by gas chromatography, will differdepending upon the crude source, the date ofthe diesel production and the producer. Inaddition, there are three basic types of dieselfuel oils: ASTM Designations No. 1-D, No. 2-D, and No. 4-D. The No. 2-D is mostcommonly referred to in terms of "dieselfuel." However, No. 2-D is sometimesblended with No. 1-D which has a lowerboiling range. Thus it is highly desirable thatthe sample chromatograms be matched witha reference standard made from the samediesel oil source suspected to be in thesample.

3. Apparatus, Reagents and Materials

3.1 Apparatus.3.1.1 Gas Chromatograph (OC)-A

temperature programmable GC equippedwith a flame ionization detector.

3.1.2 Integrator-A recording integratorcapable of resolving and integrating recorderresponse peaks.

3.1.3 Chromatographic Column-Aborosilicate glass capillary column (WCOT),30 meter x 0.25 mm ID, coated with SupelcoSPB-1 (Bonded SF-30 methyl silicone) with1.0 tm thickness (Supelco catalog number 2-4029). Other colur.ins may be substituted ifthey can demonstrate similar and satisfactoryresults.

3.1.4 Distillation Apparatus-A 20 mLvetort apparatus.

3.1.5 Kuderna-Danish Concentrator-A500 mL flask, 3-ball Snyder column and a 10mL (or 15 mL) receiving ampule graduated in0.1 ml units at the bottom.

3.1.6 Separatory Funnel-A 60 mLseparatory funnel with a Teflon stopcock andglass stopper.

3.1.7 Glass Filtering Funnel-A glassfiltering crucible holder (Coming 9480 orequivalent).

3.1.8 Centrifuge Tubes-15 mL glasscentrifuge tubes.

3.2 Materials and Reagents.3.2.1 Glass Wool-Coming 3950 or

equivalent.3.2.2 Anhydrous Sodium Sulfate-

Analytical grade.3.2.3 Methylene Chloride-Nanograde or

equivalent.3.2.4 Trichlorobenzene (TCB) Internal

Standard-Dissolve 1.0 gm of 1,3,5Trichlorobenzene (Kodak 1801 or equivalent)in 100 mL of Methylene Chloride. Store inglass and tightly cap with Teflon lid liner toprevent solvent evaporation loss.

4. Procedure4.1 Sample Preparation.4.1.1 Preweigh or tare the retort sample

cup and cap to the nearest 0.1 gm. Transfer awell homogenized and representative portionof the material to be tested into the samplecup. filling it to the top. Place the cap on the

cup, wipe off the excess material andreweigh. Record the weight of the sample tothe nearest 0.1 gm.

4.1.2 Following the retort manufacturer'sinstructions, distill the sample. The presenceof solids in the distillate will require that thedistillation be rerun starting with a newportion of sample. Placing more steel wool inthe retort expansion chamber, perinstructions, will help prevent the solids fromgoing over in the distillation.

4.2 Gas Chromatography.4.2.1 Pour the retort distillate into a 60 mL

separatory funnel. Rinse the distillatecontainer with two full portions of methylenechloride into the separatory funnel. Stopperand shake for 1 minute and allow the layersto separate.

4.2.2 Prepare a crucible holder funnel byplugging the bottom with a piece of glasswool and pouring in 1-2 inches of anhydroussodium sulfate. Wet the funnel with a smallportion of methylene chloride and allow it todrain to a waste container.

4.2.3 Place the filter holder into the top ofa Kuderna-Danish (K-D) flask equipped witha 10 mL separatory funnel containing themethylene chloride into the K-D flask passingit thorough the filter funnel.

4.2.4 Repeat the methylene chlorideextraction twice more, rinsing the centrifugetube with two through washings each timeand draining each extraction into the K-Dflask.

4.2.5 Place a Snyder column on the K-Dflask and evaporate on a steam bath.Concentrate the sample to a 1.0 mL finalvolume or until the contents will notconcentrate any further and note the finalvolume. The receiving ampule graduationsshould be laboratory calibrated for accuracy.

4.2.6 Using a micropipet, transfer equalportions of the sample from the K-D ampuleand the TCB internal standard (a 100 filportion of each is suggested) into a GCinjection vial or other suitable container. Mixthoroughly.

4.2.7 Set up the gas chromatographconditions as follows:

(a) GC-Injector Port and manifoldtemperature=275 'C.

(b) Column-A SPB-1, 30 meter columnwith a nitrogen carrier at 0.2 mL/min, a splitratio of 100:1 and nitrogen make-up (ifneeded) at 60 cc/min.

(c) Temperature Program-90 °C initialtemperature with no hold, 5* per minute to afinal temperature of 250 °C; final hold for atleast 10 minutes.(d) Detector-FID with 30 cc/min hydrogen

and 240 cc/min air. Set the amplifier range at10- 1 amps full scale (X10 on mostinstruments)

(e) Recording Integrator-Set the chartseed at a minimum of I cm/min. Adjust theattenuation during the run as to excludeminor peaks.

4.2.8 Inje6t 1 pL of the sample containingthe internal standard. The TCB will elute atapproximately 8.5 minutes into the run andshould be approximately 50"percent at fullscale at 8X10.

4.2.9 Prepare a reference standard using,if possible, the same diesel-oil suspected tobe in the sample. Using Table 1 as a guide,

Federal Register / Vol. 50, No. 165 / Monday, August 26, i385 / Proposed Rules

weigh out the appropriate amount of oil into atared 10 mL volumetric flask and dilute tovolume with methylene chloride. Mix equalportions of the reference oil standard and theTCB as outlined in 4.2.6 and analyze using thesame GC conditions used for the analysis ofthe sample.

5. Interpretation of Data

5.1 Compare the sample chromatogram tothe chromatogram of the standard. If thesample contains No. 2 diesel oil, the majorpeaks present in the standArd (e.g. thosegreater than 1 percent of the total integratedarea) should also be present in the sampleand in the same relative intensity and pattern(see Figure 1).

5.2 Some mineral oil lubricity additiveshave similar chromatographic patterns to thatof diesel oil. The presence of early, smallerpeaks from 1 minute (following the soventpeak) to approximately 4 minutes willdifferentiate between distillates containingonly mineral oil and those with No. 2 dieseloil (See Figure 2).

5.3 The use of the TCB internal standardmakes it possible to correlate peaks fromsample to standard on the basis of RelativeRetention Time (RTT). Approximate RRr'sare presented In Tab* 2.

6. Calculation of Results *

6.1 Choose those peaks that areapplicable as outlined in'Section 5; aminimum of 10 peaks should be used. Sumthe integrated areas of the chosen peaks inthe sample and divide by the integrated areaof the Internal Standard in the sample:

-Apr - RFrAir

where;lAps- Summation of peak areas of interest

in sampleAis -Area of internal standard peak in

sampleRFs -Response factor for sample

6.2 Repeat the above process [6.1) for thediosen peaks in the standard:

lApr-... =RFr

Air

where:YApr=Summation of peak areas of interest

in reference standard

mg/kg Diesel Oil=

where:RFs=Response factor for sampleRFr=Response factor for reference standardVs =Final volume of sample from K-D in mLCr= Concentration of reference standard In

mg/mLGs :Starting weight of sample in grams on a

wet weight or whole mud basis.Note,-Thlis equation does not take into

account attenuation changes if tbey affect thecalculated peak areas as reported by theIntegration.

7. Quality Control

7.1 Each laboratory that us this methodIs required to operate a formal quality controlprogram. The minimum requirements of thisprogram consist of an initial demonstratinn ofLaboratory capability, the analysis of.retorted No. 2 diesel oil standard as acontinuing check on recovery, and duplicatesamples for a precision check onperformance. The laboratory Is required tomaintain performance records to define thequality of data that are generated. Ongoingperformanrce checks nust be compared withestabllshe l performa ce criteria to determineIf the results of analyues are within accuracyand precision limits expected of the method.

7.2 In order to demonstrate recovery, aNo. 2 diesel oil standard must be subjected tothe entire analytical procedure starting withsection 4.1. Pipette 1.00 ml of the referencediesel oil into the preweighed or tared retortsample cup and weigh to the nearest 0.1gram. Place a small plug of steel wool into the

Air= Area of internal standard peak in thereference standard

RFr=Response factor for reference standard

6.3 Calculate the mg/kg of diesel oil in thesample as follows:

RFsxVsxCrxlOOO

RFr x Gs

cup, cap and proceed with the retortdistillation. Calculate the percent recovery ofthe retorted reference standard to that of areference standard prepared as specified insection 4.2.9. The percent recovery of theretorted reference standard must fall within80 to 120 percent recovery. This should beperformed on each retort unit utilized beforeattempting any sample analyses. Referencestandards should be run at least once foreach batch of samples processed or for everyten samples analyzed,

7.3 The laboratory must analyze duplicatesamples for each sample type at a minimumof 20 percent. A duplicate sample shallconsist of a well-mixed, representativealiquot of the sample and should be subjectedto the entire analytical procedure startingwith section 4.1. The relative percentdiffarence. (RPD) for duplicates arecalculated as follows:

(D1 -1%)RPD= (D.+1D)I XlO

2

where:RPD= relative percent differenceD, =percent of diesel oil in the first sampleD2 =percent diesel oil in the second sample

(duplicate)A control limit of ±20 percent for RPD shallbe used.

BILLING CODE 6560-50-M

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FIGURE ICHROMATOGRAM OF NO.2 DIESEL OIL SAMPLE

(NO SOLVENT OR INTERNAL STANDARD PEAKS PRESENT)

0 i0 20 30

RUN TIME (MINUTES)

FIGURE 2

CHROMATOGRAM OF MINERAL OIL SAMPLE250-A

BILLING CODE 6560-50-C

20 30 40 50

RUN TIME (MINUTES)

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--'A 'YUA4 I I


TABLE 1.-PERCENT RANGES OF DIESEL ANDSTANDARDS

Expected percent diesel In Wt of No. 2-D oil in 10 mLsample volumetric'(9)

5 -....... ..... ...... Use uncited oil3 ................................. ...... 7.6.0 ................ 1.5.

Weigh oil to the nearest 0.1 mg

Table 2

Approximate Relative Retention Times forTCB IS and No. 2-D Diesel Fuel.1,3.5 Trichlorobenzene Internal

Standard=100Expected RRT's for Predominate Peaks in No. 2-

D Diesel:124 231155 245179 260183 27318 276188 299193 324207 348216 370220

Appendix 3-Drilling Fluids Toxicity Test

. Sample Collection

The collection and preservation methodsfor drilling fluids (muds) and water samplespresented here are designed to minimizesample contamination and alteration of thephysical or chemical properties of thesamples due to freezing, air oxidation, ordrying.

I-A. Apparatus

(1) The following items are required forwater and drilling mud sampling and storage:

a. Acid-rinsed linear-polyethylene bottlesor other appropriate noncontaminatingdrilling mud sampler.

b. Acid-rinsed linear-polyethylene bottlesor other appropriate noncontaminating watersampler.

c. Acid-rinsed linear-polyethylene bottlesor other appropriate noncontaminatedvessels for water and mud samples.

d. Ice chests for preservation and shippingof mud and water samples.

I-B. Water Sampling

(1) Collection of water samples shall bemade with appropriate acid-rinsed linear-polyethylene bottles or other appropriatenoncontaminating water sampling devices.Special care shall be taken to avoid theintroduction of contaminants from thesampling devices and containers. Prior to use.the sampling devices and containers shouldbe thoroughly cleaned with a detergentsolution, rinsed with tap water, soaked in 10percent hydrochloric acid (HCI) for 4 hours.and then thoroughly rinsed with glass-distilled water.

I-C. Drilling Mud Sampling

(1] Drilling mud formulations to be testedshall be collected from active field systems.Obtain a well-mixed sample from beneaththe shale shaker after the mud has passedthrough the screens. Samples shall be storedin polyethylene containers or in other

appropriate uncontaminated vessels. Prior tosealing the sample containers on theplatform, flush as much air out of thecontainer by filling it with drilling fluidsample, leaving a one inch space at the top.

(2) Mud samples shall be immediatelyshipped to the testing facility on blue or wetice (do not use dry ice) and continuouslymaintained at 4 °C until the time of testing.

(3) Bulk mud samples shall be thoroughlymixed in the laboratory by using a 1,000-rpmhigh-shear mixer and then subdivided intoindividual, small wide-mouthed (e.g., one- ortwo-liter non-contaminating containers forstorage.

(4) The drilling muds stored in thelaboratory shall have any excess air removedby flushing the storage containers withnitrogen any time the containers are opened.Moreover, the sample in any containeropened for testing must be thoroughly stirredby using a 1,000-rpm high-shear mixer prior touse.

(5) Most drilling mud samples may bestored for periods of time longer than 2 weeksprior to toxicity testing, provided that propercontainers are used and proper conditionsare maintained.

I1. Suspended Particulate Phase SamplePreparation

(1) Mud samples that have been storedunder specified conditions in this protocolshall be prepared for tests within threemonths after collection. The SPP shall beprepared as detailed below.

1l-A Apparatus

(1) The following items are required:a. Magnetic stir plates and bars.b. Several graduated cylinders, ranging in

volume from 10 mL to 1L.c. Large (15-cm) powder funnels.d. Several 2-L graduated cylinders.e. Several 2-L large mouth graduated

Erlenmeyer flasks.(2) Prior to use, all glassware shall be

thoroughtly cleaned, Wash all glassware withdetergent, rinse five times with tap water,rinse once with acetone, rinse several timeswith distilled or deionized water, place in aclean 10-percent (or stronger) HCI acid bathfor a minimum of 4 hours, rinse five timeswith tap water, and then rinse five times withdistilled or deionized water. For test samplescontaining mineral oil or diesel oil, glasswareshould be washed with petroleum ether toassure removal of all residual oil.

Note.-lf the glassware with nytex cupssoaks in the acid solution longer than 24hours, then an equally long deionized watersoak should be performed.

11-B. Test Seawater Sample Preparation

(1) Diluent seawater and exposureseawater samples are prepared by filtrationthrough a 1.0-micrometer filter prior toanalysis.

(2) Artificial seawater may be used as longas the seawater has been prepared bystandard methods or ASTM methods, hasbeen properly "seasoned," flitered, and hasbeen diluted with distilled water to the samespecified 20± 2ppt salinity and 20± 2°Ctemperature as the natural seawater.

11-C. Sample Preparation

(1) The pH of the mud shall be measuredbefore use. If the pH is less than 9, if blackspots appear on the walls of the samplecontainer, or if the mud sample has a foulodor, that sample shall be discarded.Subsample a manageable aliquot of drill mudfrom the well-mixed original sample. Mix themud and filtered test seawater in avolumetric mud-to-water ratio of I to 9. Thisis best done by the method of volumetricdisplacement in a 2-L, large mouth, graduatedErlenmeyer flask. Place 1,000 mL of seawaterinto the graduated Erlenmeyer flask. The mudsubsample is then carefully added funnel toobtain a total volume of 1,200 mL (A 200-mLvolume of mud will now be in the flask).

The 2-L, large mouth, graduatedErlenmeyer flask is then filled to the 2,000 .mlmark with 800 mL of seawater, whichproduces a slurry with a final ratio of onevolume drilling mud to nine volunms water. Ifthe volume of SPP required for testing oranalysis exceeds 1,500 to 1,600 mL, the initialvolumes should be proportionately increased.Alternatively, several 2-L drill mud/waterslurries may be prepared as outlined aboveand combined to provide sufficient SPP.

(2) Mix this mud/seawater slurry withmagnetic stirrers for 5 minutes. Measure thepH and, if necessary, adjust (decrease) thepH of the slurry to within 0.2 units of theseavw ater by adding 6N HCI while stirring theslurry. Then, allow the slurry to settle for 1hour. Record the amount of HCI added.

(3) At the end of the settling period,carefully decant (do not siphon) theSuspended Particulate Phase (SPP into anappropriate container. Decanting the SPP is,one continuous action. In some cases, noclear interface will be present; that is, therewill be no solid phase that has settled to thebottom. For those samples the entire SPPsolution should be used when preparing testconcentrations. However, in those caseswhen no clear interface is present, the samplemust be remixed for five minutes. Thisinsures the homogeneity of the mixture priorto the preparation of the test concentrations.In other cases, there will be samples with twnor more phases, including a solid phase. Forthose samples, carefully and continuouslydecant the supernatant until the solid phaseon the bottom of the flask is reached. Thedecanted solution is defined to be 100 percentSPP. Any other concentration of SPP refers toa percentage of SPP that is obtained byvolumetrically mixing 100 percent SPP withseawater.

(4) SPP samples to be used in toxicity testsshall be mixed for 5 minutes and must not bepreserved or stored.

(5) Measure the filterable and unfilterableresidue of each SPP prepared for testing.Measure the dissolved oxygen (DO) and pHof the SPP. If the DO is less than 4.9 ppm,aerate the SPP to at least 4.9 ppm which is 65percent of saturation. Maximum allowableaeration time is 5 minutes using a genericcommercial air pump and air stone.Neutralize the pH of the SPP to a pH 7.8±.1using a dilute HCI solution. If too much acidis added to lower the pH saturated NaOHmay be used to raise the pH 7.8±.1 units.Record the amount of acid or NaOH needed

34631


to adjust to the appropriate pI. Threerepeated DO and pH measurements areneeded to insure homogeneity and stability ofthe SPP. Preparation of test concentrationsmay begin after this step is complete.

(6) Add the appropriate volume of 100percent SPP to the appropriate volume ofseawater to obtain the desired SPPconcentration. The control is seawater only.Mix all concentrations and the control for 5minutes by using magnetic stirrers. Recordthe time; and, measure DO and pH for Day 0.Then, the animals shall be randomly selectedand placed in the dishes in order to begin the96-hour toxicity test.

111. Guidance for Performing SuspendedParticulate Phase Toxicity Tests UsingMysidopsis bahia

II-A. Apparatus

(1) Items listed by Borthwick I are requiredfor each test series, which consists of one setof control and test containers, With threereplicates of each.

111-B. Sample Collection Preservation

(1) Drilling muds and water samples arecollected and stored, and the suspendedparticulate phase prepared as described inSection 1-C.

3-C. Species Selection(1) The suspended particulate phase (SPP)

tests on drilling muds shall utilize the testspecies Mysidopsis bahia. Test animals shallbe 3 to 6 days old on the first day ofexposure. Whatever the source of theanimals, collection and handling should be usgentle as possible. Transportation to thelaboratory should be in well-aerated waterfrom the animal culture site at thetemperature and salinity in which they werecultured. Methods for handling, acclimating,and sizing test organisms given byBorthwick I and Nimmo 2 shall be followed inmatters for which no guidance is given here.

III-D. Experimental Conditions

(1) Suspended particulate phase (SPP] testsshould be conducted at a salinity of ±2 ppt.Experimental temperature should be 20±L2*C. Dissolved oxygen in the SPP shall beraised to or maintained above 65 percent ofsaturation prior to preparation of the testconcentrations. Under these conditions oftemperature and salinity, 65 percent ofsaturation is a DO of 5.3 ppm. Beginning atDay 0- before the animals are placed in thetest containers DO, temperature, salinity, andpH shall be measured every 24-hours, DOshould be reported in milligrams per liter.

(2) Aeration of test media is requiredduring the entire test with a rate estimated tobe 50-140 cubic centimeters/minute. This airflow to each test dish may be achievedthrough polyethylene tubing (0.045-inch inner

I Borthwick, Patrick W. 1978. Methods for acutestatic toxicity tests with mysid shrimp (Mysidapsisbohia). Bioassay Procedures for the Ocean DisposalParmit Program, EPA--00/9-78-010: March.

2 Nimmo. DR., T.L. Hamaker, and C.A. Somers.1978., Culturing the mysid (Mysidopsis bahia) inflowing sea water or a static system. BioassayProcedures for the Ocean Disposal Permit Program,EPA-600/9-78-010: March.

diameter and 0.002-inch outer diameter) by asmall, generic aquarium pump. The deliverymethod, surface area of the aeration stone,and flow characteristics shall bedocumented. All treatments, includingcontrol, shall be the same.

(3) Light intensity shall be 1,20amicrowatts/cm 2, using cool white fluorescentbulbs with a 14-hour light and 10-hr darkcycle. This light/dark cycle shall also bemaintained during the acclimation period andthe test.

III-E. Experimental Procedure

(1) Wash all glassware with detergent,rinse five times with tap water, rinse oncewith acetone, rinse several times withdistilled or deionized water, place in a clean10 percent JICI acid bath for a minimum of 4hours, rinse five times with tap water, andthen rinse five times with distilled water.

(2) Establish the definitive testconcentrations based on the results of arange-finding test. A minimum of five testconcentrations plus a control and positivecontrol (reference toxicant) is required for thedefinitive test. To estimate the LC-50, twoconcentrations shall be chosen that shouldgive (other than zero and 100 percent)mortality above and below 50 percent.

(3) Twenty organisms are exposed in eachtest dish. Nytex® cups shall be inserted intoevery test dish prior to adding the animals.,These "nylon mesh screen" holding cups arefabricated by gluing a collar of 363-micrometer mesh nylon screen to a 15-centimeter wide Petri dish with siliconesealant. The nylon screen collar isapproximately 5 centimeters high. Theanimals are placed into the test concentrationwithin the confines of the Nytex® cups.

(4) Individual organisms shall be randomlyselected and assigned to treatments. Arandomization procedure is presented inSection V of this protocol. Make everyattempt to expose animals of approximatelyequal size. The technique described byBorthwick,I or other suitable substitutes,should be used for transferring specimens.Throughout the test period, mysids shall befed daily with approximately 50 Artemia(brine shrimp) nauplii per mysid. This willreduce stress and decrease cannibalism.

(5) Cover the dishes, aerate, and incubatethe test containers in an appropriate testchamber. Positioning of the test containrersholding various concentrations of testsolution should be randomized if incubatorarrangement indicates potential positiondifference. The test medium is not replacedduring the 96-hour test.

(6) Observations may be attempted at 4, 6and 8 hours. They must be attempted at 0, 24,48, and 72 hours; and, must be made at 96hours. Attempts at observations refers toplacing a test dish on a light table andvisually counting the animals. Do not lift the'nylon mesh screen" cup out of the test dishto make the observation. No unnecessaryhandling of the animals should occur duringthe 96-hour test period. DO and pHmeasurements must also be made at 0, 24, 48,72, and 96 hours. Take and replace the testmedium necessary for the DO and p1i

measurements outside of the Nytex) cups tominimize stresses on the animals.

(7) At the end of 96 hours, all live animalsmust be counted. Death is the end point, sothe number of living organisms is recorded.Death is determined by lack of spontaneousmovement. All crustaceans molt at regularintervals, shedding a complete exoskeleton.Care should be taken not to count anexoskeleton. Dead animals might decomposeor be eaten between observations. Therefore,always count living, not dead animals. Ifdaily observations are made, remove deadorganisms and molted exoskeletons with apipette or forceps. Care must be taken not todisturb living organisms and to minimize theamount of liquid withdrawn.

IV. lethods for Positive Control Tests(Reference Toxicant)

(1) Sodium lauryl sulfate (dodecyl sodiumsulfatel is used as a reference toxicant for thepositive control. The chemical used should beapproximately 95 percent pure. The source,lot number, and percent purity shall bereported.

(2) Test methods are those used for thedrilling fluid tests, except that the testmaterial was prepared by weighing one gramof sodium lauryl sulfate on an analyticalbalance, adding the chemical to a 100-milliliter volumetric flask, and bringing theflask to volume with deionized water. Aftermixing this stock solution, the test mixturesare prepared by adding 0.1 milliliter of thestock solution for each part per milliondesired to one liter of seawater.

(3) The mixtures are stirred briefly, waterquality is measured, animals are added toholding cups, and the test begins. Incubationand monitoring procedures are the same asthose for the drilling fluids.

V. Randomization Procedure

V-A. Purpose and Procedure

(1) The purpose of this procedure is toassure that mysids are impartially selectedand randomly assigned to six test treatments(five drilling fluid or reference toxicantconcentrations and a control) and impartiallycounted at the end of the 96-hour test. Thus,each text setup, as specified in therandomization procedure, consists of 3replicates of 20 animals for each of the sixtreatments, i.e., 360 animals per test. Figure Iis a flow diagram that depicts the procedureschematically and should be rcviewed tounderstand the over-all operation. Thefollowing tasks shall be performed in theorder listed.

(2) Mysids are cultured in the laboratory inappropriate units. If mysids are purchased, goto Task 3.

(3) Remove mysids from culture tanks (6, 5.4, and 3 days before the test will begin, i.e.Tuesday, Wednesday, Thursday, and Fridayif the test will begin on Monday) and placethem in suitably large maintenancecontainers so that they can swim about freelyand be fed.

Note.-Not every detail (the definition ofsuitably large containers, for example) isprovided here. Training and experience inaquatic animal culture and testing will berequired to successfully complete these tests.

34632

Federal Register / Vol. 50, No. 165 / Monday. August 26. 1985 / Prnnsd Rules

(4) Remove mysids from maintenancecontainers and place all animals in a singlecontainer. The intent is to have ahomogeneous test population of mysids of aknown age (3-6 days old).

(5) For each toxicity test, assign twosuitable containers (500-milliliter [mL)beakers are recommended) for mysidseparation/enumeration. Label eachcontainer (Al, A2, B1, B2, and C1, C2, forexample, if two drilling fluid tests and areference toxicant test are to be set up on oneday). The purpose of this task is to allow theinvestigator to obtain a close estimate of thenumber of animals available for testing andto prevent unnecessary crowding of themysids while they are being counted andassigned to test containiers. Transfer themysids from the large test populationcontainer to the labeled separation andenumeration containers but do not place

more than 200 mysids in a 500-mL beaker. Beimpartial in transferring the mysids; placeapproximately equal numbers of animals (10-15 mysids is convenient) in each container ina cyclic manner rather than placing themaximum number in each container at onetime.

Note.-It is important that the animals notbe unduly stressed during this selection andassignment procedure. Therefore, it willprobably be necessary to place all animals(except the batch immediately being assignedto test containers) in mesh cups with flowingseawater or in larger volume containers withaeration. The idea is to provide the animalswith near optimal conditons to avoidadditional stress.

(6) Place the mysids from the two labeledenumeration containers assigned to a specifictest into one or more suitable containers tobe used as counting dishes (2-liter Carolina

dishes are suggested). Because of the timerequired to separate, count, and assignmysids, two or more people may be involvedin completing this task. If this is done, two ormore counting dishes may be used, but theinvestigator must make sure thatapproximately equal numbers of mysids fromeach labeled container are placed in eachcounting dish.

(7) By using a large-bore, smooth-tip glasspipette, select mysids from the countingdish[es) and place them in the 36 individuallynumbered distribution containers (10-mlbeakers are suggested). The mysids areassigned two at a time to the 36 containers byusing a randomization schedule similar to theone presented below. At the end of selection/assignment round 1, each container willcontain two mysids; and so on until eachcontains ten mysids.


iAA.Q1


Figure

Mysid Randomization Procedure

1 Culture Units LuuiJLziLzi Mysids Are Collected3 To 6 Days Prior

To Testing

2 MaintenanceContainer(s)

Test PopulationContainer(s)

<== If MysidsAre Purchased

Separation/4 Enumeration

Containers

Counting Dish(repeat taks 5-7

for At & A2 containmrv)

Distribution6 Containers

7 CTest7Con tainers

272-ASILLING CODE 6560-50-C

Tosk

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EXAMPLE OF A RANDOMIZATION SCHEDULE

Selection/assignment Place mysid in the rumbered distribution

round (2 mysids containers in the random order showneach)

1 ............................. 8, 21, 6, 28 , 33 , 32. 1, 3, 10, 9, 4, 14,23, 2, 34. 22. 36, 27, 5, 30, 35. 24. 12,25, 11. 17, 19, 26, 31. 7, 20, 15, 18,13, 16, 29

2 ............................. 35. 18. 5, 12, 32. 34, 22, 3, 9. 16, 26,13, 20. 28, 6, 21, 24, 30, 8, 31, 7. 23,2. 15, 25, 17. 1. 11, 27, 4, 19, 36, 10,33. 14, 29

3.............. .......... 7. 19, 14, 11, 34. 21, 25, 27, 17, 18, 6,16. 29, 2. 32. 10, 4, 20, 3, 9, 1, 5, 28.24, 31, 15, 22. 13, 33, 26, 36, 12, 8,30, 35, 23

4 ............................ 30, 2, 18, 5, 8, 27, 10, 25, 4, 20, 26, 15,31, 36, 35. 23. 11, 29, 16, 17. 28, 1.33. 14, 9, 34. 7, 3, 12. 22. 21, 6, 19,24, 32, 13

5 .......... ........... 34, 28, 16, 17, 10, 12, 1, 36, 20, 18, 15,22, 2. 4, 19, 23. 27, 29, 25, 21, 30, 3,9, 33, 32, 6, 14, 11, 35, 24, 26, 7, 31.5, 13,8

(8) Transfer mysids from the 36 distributioncontainers to 18 labeled test containers inrandom order. A label is assigned to each ofthe three replicates (A, B, C of the six testconcentrations. Count and record the 96 hourresponse in an impartial order.

(9) Repeat tasks 5-7 for each toxicity test.A new random schedule should be followedin Tasks 6 and 7 for each test.

Note.-If a partial toxicity test isconducted, the procedures described aboveare appropriate and should be used toprepare the single test concentration andcontrol, along with the reference toxicanttest.

V-B. Data Analysis and Interpretation

(1) Complete survival data in all testcontainers at each observation time shall bepresented in tabular form. If greater than 10percent mortality occurs in the control, theexperiment shall be repeated. Unacceptablyhigh control mortality indicates the presenceof important stresses on the organisms otherthan the material being tested, such as injuryor disease, stressful physical or chemicalconditions in the containers, or improperhandling, acclimation, or feeding. If 10percent mortality or less occurs in thecontrol, the data may be evaluated andreported.

(2) A definitive, full toxicity test conductedaccording to the EPA protocol is used toestimate the concentration that is lethal to 50percent of the test organisms that do not dienaturally. This toxicity measure is known asthe median lethal concentration, or LC-50.The LC-50 is adjusted for natural mortality ornatural responsiveness. The maximumlikelihood estimation procedure with theadjustments for natural responsiveness asgiven by D.J. Finney, in Probit Analysis 3rdedition, 1971, Cambridge University Press,Chapter 7, can be used to obtain the probitmodel estimate of the LC-50 and the 95percent fiducial (confidence) limits for theLC-50. These estimates are obtained by usingthe logarithmic transform of theconcentration. The heterogeneity factor(Finney 1971. pages 70-72) is not used. For atest material to pass the toxicity testaccording to the requirements stated in theoffshore oil and gas extraction industry BAT

regulation, the lower 95 percent limit for theLC-50 adjusted for natural responsivenessmust be greater than 3 percent suspendedparticulate phase (SPP) concentration byvolume unadjusted for the I to 9 dilution."Other toxicity test models may be used toobtain toxicity estimates provided themodeled mathematical expression for thelethality rate must increase continuously withconcentration. The lethality rate is modeledto increase with concentration to reflect anassumed increase with concentration toreflect an assumed increase in toxicity withconcentration even though the observedlethality may not increase uniformly becauseof unpredictable animal responsefluctuations.

(3) The range-finding test is used toestablish a reasonable set of testconcentrations in order to run the definitivetest. However, if the lethality rate changesrapidly over a narrow range ofconcentrations, the range-finding test may betoo coarse to establish an adequate set of testconcentrations for a definitive test.

(4) The EPA Environmental ResearchLaboratory in Gulf Breeze, Florida prepared aResearch and Development Report titledAcute Toxicity of Eight Drilling Fluids toMysid Shrimp (Mysidopsis bahia), May 1984EPA-600/3-84-067. The Gulf Breeze data fordrilling fluid number 1 are displayed in Table1 for purposes of an example of the probitanalysis described above. The SAS ProbitProcedure (SAS Institute, Statistical AnalysisSystem, Cary, North Carolina, 1982) was usedto analyze these data. The 96-hour LC-50adjusted for the estimated spontaneousmortality rate is 3.3 percent SPP with 95percent limits of 3.0 and 3.5 percent SPP withthe I to 9 dilution. The estimatedspontaneous mortality rate based on all ofthe data is 9.6 percent.

TABLE 1.-LISTING OF ACUTE TOXICITY TESTDATA (AUGUST 1983 TO SEPTEMBER 1983)WITH EIGHT GENERIC DRILLING FLUIDS ANDMYSID SHRIMP-FLUID N2= 1

Number Number NumberPercent concentration dead alive (96exposed (96 hrs) hrs)

0 ................................................. 60 3 571 ............................ 60 11 492 ................................................. 6 0 11 493 ........................................ 60 25 354 ................................................ 60 48 125 ................................................. 60 60 0

V-C. The Partial Toxicity Test for Evaluationof Test Material

(1,) A partial test conducted according toEPA protocol can be used economically todemonstrate that a test material passes thetoxicity test. The partial test cannot be usedto estimate the LC-50 adjusted for naturalresponse.

(2) To conduct a partial test, follow the testprotocol for preparation of the test materialand organisms. Prepare the control (zeroconcentration), one test concentration (3percent suspended particulate phase) and thereference toxicant according to the methodsof the full test. A range finding test is notused for the partial test.

(3) Sixty test organisms are used for eachtest concentration. Find the number of testorganisms killed in the control (zero percentSPP) in the column labeled X. of Table 2. Ifthe number of test organisms killed in thecontrol (zero percent SPP) exceeds the tablevalues, then the test is unacceptable andmust be repeated. If the number of organismskilled in the 3 percent test concentration isless than or equal to corresponding number inthe column labeled X then the test materialpasses the partial toxicity test. Otherwise thetest material fails the toxicity test.

TABLE 2.

Xo X,

0 ..................................................................................... ... 221 .................................................................................... ... 222 ..................................................................................... ... 233 ..................................................................................... .. 234 ....................................................................................... 245 ....................................................................................... 246 ..................................................................................... ... 25

(4) Data shall be reported as percentsuspended particulate phase.

6. References

(1) Borthwick, Patrick W. 1978. Methods foracute static toxicity tests with mysid shrimp(Mysidopsis bahia. Bioassay Procedures forthe Ocean Disposal Permit Program, EPA-600/9-78-010: March.

(2) Nimmo, D.R., T.L. Hamaker, and C.A.Somers. 1978. Culturing the mysid(Mysidopsis bahia) in flowing sea water or astatic system. Bioassay Procedures for theOcean Disposal Permit Program, EPA-600/9-78-010: March.

(3) American Public Health Association etal. 1980. Standard Methods for theExamination of Water and Wastewater.Washington, D.C. 15th Edition: 90-99.

Appendix 4-Regulatory Boundaries

New source offshore oil productionfacilities located in or discharging to thefollowing areas are subject to the zerodischarge standard for produced water,depending upon water depth at the locationof the facility or discharge. Unless otherwisestated below, the outer boundary for eachdesignated area is the 200-mile boundary ofthe 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 Western Florida.

(B) Atlantic Coast-Water Depth 20 Metersor Less

Extending from the inner boundary of theterritorial seas offshore of the contiguousstates betweeri and including Maine andFlorida.

(C) California Coast-Water Depth 50Meters or Less

2. Central and Northern California:Extending offshore of California and boundedon the north by approximately 42 * N. latitudeand bounded on the south by the U.S.-Mexicoboundary.

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(D) Alaska

1. Gulf of Alaska-Water Depth 50 metersor less: It is bounded approximately on thewest by 151. 55' W. longitude; thence eastalong 590 N latitude to 148* W longitude;thence south to 58' N latitude; thence eastalong 580 N latitude to 147* W longitude,thence south.

2. Cook Inlet/Shelikof Strait-Water Depth50 Meters or Less: Lies east of 156 * W.longitude and north of 570 N latitude to theinner boundary of the territorial seas nearKalgin 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 590 N latitude. It is bounded on the

west 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 Bering Seanorthwest of the Aleutina Islands chain andis bounded on the north by 590 N latitude andon the west by 1740 W longitude from 59" N.latitude to 560 N. latitude; thence east to 1710W. longitude, thence south. It is bounded onthe 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 03*N. latitude, on the west by the U.S.-RussiaConvention Line of 1867, on the north by 65034' 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 on

the west by the Mineral Management ServiceChukchi Sea planning area, extends eastwardto the limit of U.S. jurisdiction, and on thesouth by the inner bounary of the territorialseas.

To determine water depth at the facilitylocation, reference the 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.

[FR Doc. 85-19100 Filed 8-23-85; 8:45 am)


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