Granular Filtration Capital and Annual 3. ADDRESSES: For 4....cadmium and mercury at 3 mg/kg and I mg/kg, respectively, in stock barite (on a dry weight basis); (3) prohibit the discharge

12454 Federal Register / Vol. 58, No. 41 / Thursday, March 4, 1993 / Rules and Regulations

ENVIRONMENTAL PROTECTIONAGENCY

40 CFR Part 435

[FRL-4537-1]

RIN 2040-AA12

Oil and Gas Extraction Point SourceCategory; Offshore SubcategoryEffluent Umitations Guidelines andNew Source Performance Standards

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

SUMMARY: This regulation establisheseffluent limitations guidelines and newsource performance standards limitingthe discharge of pollutants to waters ofthe United States from the offshoresubcategory of the oil and gas extractionpoint source category. This rule ispromulgated under authority granted toEPA by the Clean Water Act and isrequired by consent.decree in NRDC v.Reilly, D. D.C. No. 79-3442 (JHP).

The regulation establishes effluentlimitations guidelines attainable by theapplication of the "best availabletechnology economically achievable"(BAT) and "best conventional pollutantcontrol technology" (BCT), andestablishes "new source performancestandards" (NSPS) attainable by theapplication of the "best availabledemonstrated technology." The existingeffluent limitations guidelines based onthe achievement of the "best practicablecontrol technology currently available"(BPT) are not being changed by thisregulation. Since offshore oil and gasfacilities currently do not discharge intopublicly owned treatment works(POTWs), pretreatment standards arenot included in this regulation.DATES: The regulation shall becomeeffective April 5, 1993.

The compliance date for NSPS is thedate the new source begins operation.Deadlines for compliance with BCT andBAT are established in NPDES permits.

In accordance with 40 CFR part 23,this regulation shall be consideredissued for the purposes of judicialreview at 1 p.m. Eastern time on March18, 1993. Under section 509(b)(1) of theClean Water Act, judicial review of thisregulation can be had only by filing apetition for review in the United StatesCourt of Appeals within 120 days afterthe regulation is considered issued forpurposes of judicial review. Undersection 509(b)(2) of the Clean Water Act,the requirements in this regulation maynot be challenged later in civil orcriminal proceedings brought by EPA toenforce these requirements.

The incorporation by reference ofcertain publications listed in theregulations is approved by the Directorof the Federal Register as of April 5,1993.ADDRESSES: For additional technicalinformation contact Mr. Ronald P.Jordan, Office of Water, Engineering andAnalysis Division (WH-552), U.S.Environmental Protection Agency, 401M Street, SW., Washington, DC, 20460,(202) 260-7115. For additionalinformation on the economic orregulatory impact analyses contact Dr.Mahesh Podar at the above address orby calling (202) 260-5387.

The complete public record for thisrulemaking, including EPA's responsesto comments received duringrulemaking, is available for review atEPA's Water Docket; 401 M Street, SW.,Washington, DC, 20460. For access toDocket materials, call (202) 260-3027between 9 a.m. and 3:30 p.m. for anappointment. The EPA publicinformation regulation (40 CFR part 2)provides that a reasonable fee may becharged for copying.FOR FURTHER INFORMATION CONTACT:Ronald P. Jordan at (202) 260-7115.

SUPPLEMENTARY INFORMATION:Overview

This preamble describes the legalauthority, background, technical andeconomic basis, and other aspects of thefinal regulation. The abbreviations,acronyms, and other terms used in thisrule are defined in appendix A to thepreamble of this rule.Organization of This RuleI. Scope of This RulemakingII. Legal Authority and Background

A. Best Practicable Control TechnologyCurrently Available (BPT)

B. Best Available TechnologyEconomically Achievable (BAT)

C. Best Conventional Pollutant ControlTechnology (BCT)

D. New Source Performance Standards(NSPS)

I1. Overview of the IndustryA. Exploration, Development and

ProductionB. New and Existing Sources1. New Source Definition2. Industry ProfileC. Waste Streams

IV. Development of the Final RegulationV. Major Changes to the Data Base for the

Final RegulationA. Drilling Fluids and Drill Cuttings1. Engineering Costsa. BAT and NSPS Costing Methodologyb. Costing Assumptions2. Drilling Waste Pollutant LoadingsB. Produced Water1. Gas Flotation Performance2. Produced Water Engineering Costsa. Gas Flotation System Capital and

Annual Costs

b. Granular Filtration Capital and AnnualCosts

c. Reinjection Capital and Annual Costsd. Regional and Total Industry Costse. Onshore Treatment Costs3. Membrane Filtration4. Produced Water Pollutant LoadingsC. Produced SandD. Well Treatment, Completion and

Workover FluidsE. Non-Water Quality Environmental

Impacts1. Drilling Fluids and Drill Cuttings2. Produced WaterF. Industry Profile

VI. Summary of the Most Significant ChangesFrom the Proposal

A. Drilling Fluids and Drill Cuttings1. BCT2. BAT and NSPSB. Produced WatersC. Produced SandD. Deck DrainageE. Well Treatment, Completion, and

Workover FluidsF. Domestic WasteG. Sanitary Waste

VII. Basis for the Final Regulation-DrillingFluids and Drill Cuttings

A. BCT1. BCT Methodology2. BCT Options Considered3. BCT Cost Test Calculationsa. Drilling Fluidsb. Drill Cuttings4. Non-Water Quality Environmental

Impacts and Other Factorsa. Solid Waste Generation and

Managementb. Energy Requirementsc. Air Emissionsd. Interaction with OCS Air Regulationse. Consumptive Water Usef. Other Factors5. BCT Option SelectionB. BAT and NSPS1. BAT and NSPS Options Considered2. Non-Water Quality Environmental

Impacts and Other Factors3. BAT and NSPS Option Selection

VIII. Basis for the Final Regulation-Produced Water

A. BCT1. BCT Options Considered2. BCT Options SelectionB. BAT and NSPS1. BAT and NSPS Options Considered2. Non-Water Quality Environmental

Impacts3. BAT and NSPS Options Selection

IX. Basis for the Final Regulation-ProducedSand

A. BCT, BAT and NSPS OptionsConsidered

B. Option SelectionX. Basis for the Final Regulation-Deck

DrainageA. Options ConsideredB. Option Selection

XI. Basis for the Final Regulation-WellTreatment, Completion, and WorkoverFluids

A. BCTB. BAT and NSPS1. BAT and NSPS Options Considered

HeinOnline -- 58 Fed. Reg. 12454 1993

Federal Register / Vol. 58, No. 41 / Thursday, March 4, 1993 / Rules and Regulations

2. BAT and NSPS Option SelectionXII. Basis for the Final Regulation-Domestic

WastesXIII. Basis for the Final Regulation-Sanitary

WastesXIV. Economic Analysis

A. IntroductionB. Economic MethodologyC. Summary of Costs and Economic

Impacts1. Basis of the Analysis2. Total Costs and Impacts of the

RegulationsD. Drilling Fluids and Drill CuttingsE. Produced Water1. BCT2. BAT3. NSPSF. Produced SandG. Well Treatment, Completion and

Workover Fluids1. BCT2. BAT and NSPSH. Deck Drainage, Sanitary, and Domestic

Wastes1. Cost-Effectiveness AnalysisJ. Regulatory Flexibility ActK. Paperwork Reduction Act

XV. Executive Order 12291A. IntroductionB. Drilling Fluids and Drill CuttingsC. Produced Water

XVI. Public Participation and Summary ofResponses to Major Comments

XVII. Best Management PracticesXVIII. Upset and Bypass ProvisionsXIX. Variances and ModificationsXX. Implementation of Limitations and

StandardsXXI. Availability of Technical InformationXXII. Office of Management and Budget

(OMB) Review

* Appendix A-Abbreviations, Acronyms, andOther Terms Used In This NoticeI. Scope of This Rulemaking

This final regulation establisheseffluent limitations guidelines andstandards of performance for theOffshore Subcategory of the Oil and GasExtraction Point Source Category undersections 301, 304, 306, 307, 308, and501 of the Clean Water Act (The FederalWater Pollution Control ActAmendments of 1972; as amended bythe Clean Water Act of 1977 and theWater Quality Act of 1987), 33 U.S.C.1311, 1314 (b), (c), and (e), 1316, 1317,1318 and 1361; 86 Stat. 816, Public Law92-500; 91 Stat. 1567, Public Law 95-217; 101 Stat. 7, Public Law 100-4 ("theAct" or "CWA"). This regulation is alsoestablished in response to a ConsentDecree entered on April 5, 1990(subsequently modified on May 28,1992) in NRDC v. Reilly, D. D.C. No. 79-3442 (JHP) and is consistent with EPA'sEffluent Guidelines Plan under section304(m) of the CWA (September 8, 1992,57 FR41000). This regulation is referredto as the offshore guidelines throughoutthis preamble.

This regulation applies to dischargesfrom offshore oil and gas extractionfacilities, including exploration,development and productionoperations, that are seaward of the innerboundary of the territorial seas. Theinner boundary of the territorial seas isdefined in section 502(8) of the CWA as"the line of ordinary low water alongthat portion of the coast which is indirect contact with the open sea and theline marking the seaward limit of inlandwaters" (hereafter referred to as"shore")., The processes and operationswhich comprise the offshore oil and gasextraction subcategory (StandardIndustrial Classification (SIC) MajorGroup 13), are currently regulated under40 CFR part 435, subpart A. The existingeffluent limitations guidelines, whichwere issued on April 13, 1979 (44 FR22069), are based on the achievement ofbest practicable control technologycurrently available (BPT).

In general, BPT represents the averageof the best existing performances of wellknown technologies and techniques forcontrol of pollutants. BPT for theoffshori subcategory limits thedischarge of oil and grease in producedwater to a daily maximum of 72 mg/Iand a thirty day average of 48 mg/l;prohibits the discharge of free oil indeck drainage; drilling fluids, drillcuttings, and well treatment fluids; and,for sanitary wastes, requires a minimum.residual chlorine content of I mg/I andprohibits the discharge of floatingsolids. BPT limitations are not beingchanged by this rule.

This rule establishes regulationsbased on best available technologyeconomically achievable (BAT) that willresult in reasonable progress toward thegoal of the CWA to eliminate thedischarge of all pollutants. At aminimum, BAT represents the besteconomically achievable performance inthe industrial category or subcategory.This rule also establishes requirementsbased on best conventional pollutantcontrol technology (B&T) andestablishes new source performancestandards (NSPS) based on the bestdemonstrated control technology.

Under this rule, EPA is establishingBCT, BAT and NSPS limitationsprohibiting the discharge of drillingfluids and drill cuttings from wellslocated within three miles from shore(the inner boundary of the territorialseas). For wells located more than threemiles from shore, BAT and NSPS: (1)Limit toxicity at 30,000 ppm in thesuspended particulate phase; (2) limitcadmium and mercury at 3 mg/kg andI mg/kg, respectively, in stock barite (ona dry weight basis); (3) prohibit thedischarge of diesel oil; and (4) prohibit

the discharge of free oil withcompliance determined by the staticsheen test. BCT is limited to the controlof conventional pollutants, and in thisrule prohibits discharges of free oilbeyond three miles from shore. Allwells drilled off the Alaskan coast areexcluded from the zero dischargelimitation; instead, all discharges ofdrilling fluids and drill cuttings offAlaska must comply with thelimitations on toxicity, cadmium,mercury, free oil, and diesel oilregardless of distance from shore.

Under BAT and NSPS, the dischargeof oil and grease in produced water willbe limited to a maximum for any oneday (referred to as daily maximum) of42 mg/l and an average of daily valuesfor 30 consecutive days (referred to asmonthly average) of 29 mg/l based onimproved operating performance of gasflotation technology. BCT for producedwater is being established equal to thecurrent BPT limitations on oil andgrease.

Discharges of produced sand areprohibited under BCT, BAT and NSPS.BCT, BAT and NSPS limitations fordeck drainage are being set equal to thecurrent BPT limitations prohibitingdischarges of free oil. Compliance withthe no discharge of free oil limit fordeck drainage is to be determined by thevisual sheen test.

For treatment, completion andworkover fluids, the rule establishesBAT and NSPS limiting the discharge ofoil and grease at a daily maximum of 42mg/l and a monthly average of 29mg/l. BCT for well treatment,completion and workover fluids is beingset equal to the BPT prohibition ondischarges of free oil (compliance bystatic sheen).

EPA is promulgating limitations ondomestic wastes which prohibit thedischarge of foam (under BAT andNSPS) and floating solids (under BCTand NSPS), and incorporate U.S. CoastGuard regulations (under BCT andNSPS) prohibiting discharges of garbageas required at 33 CFR part 151. Forsanitary wastes, EPA is promulgatingBCT and NSPS limitations equal to BPTlimitations on floating solids andresidual chlorine. EPA is notestablishing BAT for sanitary wastesbecause no toxic or nonconventionalpollutants of concern have beenidentified in these wastes.

I. Legal Authority and BackgroundThis regulation is promulgated under

the authority of sections 301, 304 (b),(c), and (e), 306, 307, 308, and 501 of theCWA.

The CWA establishes acomprehensive program to "restore and

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1243,6 Federal Register / Vol. 58, No. 41 / Thursday, March 4, 1993 / Rules and Regulations

maintain the chemical, physical, andhiological integrity of the Nation'swaters" (CWA section 101(a)). Toimplement the Act, EPA is to issuetechnology-based effluent limitationsguidelines, new source performancestandards and pretreatment standardsfor industrial dischargers. The levels ofcontrol associated with these effluentlimitations guidelines and the newsource performance standards for directdischargers are summarized brieflybelow. Since no offshore facilitiescurrently discharge into publicly-ownedtreatment works (POTWs), pretreatmentstandards are not included in this ruleand are reserved.

A Consent Decree that was entered onApril 5, 1990 (NRDCv. Reilly, D.D.C.No. 79-3442), required EPA to proposeor repropose BAT and BCT effluentlimitations guidelines and new sourceperformance standards for producedwater, drilling fluids and drill cuttings,well treatment fluids, and producedsand by November 16, 1990. The 1990Consent Decree required EPA topromulgate final guidelines andstandards for these wastestreams byJune 19, 1992. Also, EPA was requiredto determine by November 16, 1990whether effluent limitations guidelinesand new source performance standardscovering deck drainage and domesticand sanitary wastes were appropriate. IfEPA determined that deck drainage anddomestic and sanitary wastes should beregulated, then final efflueut guidelinesand standards covering these wastestreams were to be promulgated by June30, 1993. On May 28, 1992, the Courtmodified the Consent Decree to extendthe date for promulgation of finaleffluent guidelines and standards forproduced water, drilling fluids and drillcuttings, well treatment fluids, andproduced sand from June 19, 1992 toJanuary 15, 1993. EPA has determinedthat rules for deck drainage, domesticwastes, and sanitary wastes areappropriate and is promulgating limitsfor these wastestrearns in this rule.

A. Best Practicable Control TechnologyCurrently Available (BPT)

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

In establishing BPT limitations, EPAconsiders the total cost in relation to theage of equipment and facilitiesinvolved, the processes employed,process changes required, engineeringaspects of the control technologies andnon-water quality environmentalimpacts (including energyr.quirements). The total cost of applying

the technology is considered in relationto the effluent reduction benefits.

B. Best Available TechnologyEconomically Achievable (BAT)

BAT limitations, in general, representthe best existing performance in theindustrial subcategory or category. TheAct establishes BAT as a principalnational means of controlling the directdischarge of toxic and nonconventionalpollutants. In arriving at BAT, EPAconsiders the age of the equipment andfacilities involved, the processemployed, the engineering aspects ofthe control technologies, processchanges, the costs and economic impactof achieving such effluent reduction,non-water quality environmentalimpacts, and such other factors as theAdministrator of EPA deemsappropriate. EPA retains considerablediscretion in assigning the weight to beaccorded these factors.C. Best Conventional Pollutant ControlTechnology (BCT)

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

9 is not an additional limitation,but replaces BAT for the control ofconventional pollutants. In addition toother factors specified in section304(b)(4)(B). the Act requires that BCTlimitations be established in light of atwo part "cost-reasonableness" test.American Paper Institute v. EPA, 660F.2d 954 (4th Cir. 1981). EPA firstpublished its methodology for carryingout the BCT analysis on August 19, 1979(44 FR 50372).

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

NSPS are based on the best available,demonstrated technology. New plantshave the opportunity to install the bestand most efficient production processesand wastewater treatment technologies.Therefore. Congress directed EPA to

consider the best demonstrated processchanges, in-plant controls, and end-of-process control and treatmenttechnologies that reduce pollution to themaximum extent feasible. In addition,in establishing NSPS, EPA is required totake into consideration the cost ofachieving the effluent reduction and anynon-water quality environmentalimpacts and energy requirements.

III. Overview of the Industry

A. Exploration, Development, andProduction

Exploration and developmentactivities for the extraction of oil andgas include work necessary to locateand drill wells. Exploration activitiesare those operations involving thedrilling of wells to determine thepotential hydrocarbon reserves.Exploratory activities are usually ofshort duration at a given site, involve asmall number of wells, and are generallyconducted from mobile drilling units.Development activities involve thedrilling of production wells once ahydrocarbon reserve has beendiscovered and delineated. Theseoperations, in contrast to explorationactivities, usually involve a largenumber of wells which may be drilledfrom either fixed or floating platforms ormobile drilling units. Productionoperations include all work necessary tobring hydrocarbon reserves from theproducing formation and begin with thecompletion of each well at the end ofthe development phase.

B. New and Existing Sources

1. New Source DefinitionThe Offshore Guidelines apply to all

mobile and fixed drilling (exploratoryand development) and productionoperations. Because many oil and gasfacilities are mobile (particularlyexploratory and development rigs),rather than stationary facilities that aretypically covered by new sourceperformance standards (NSPS), EPA's1985 proposal discussed at length thequestion of which of these facilitiesshould be considered new sources andwhich should be considered existingsources under these Guidelines. 50 FR34617-34619 (Aug. 26, 1985).

As discussed in that proposal,provisions in the NPDES regulationsdefine "new source" (40 CFR 122.2) andestablish criteria for a new sourcedetermination. (40 CFR 122.29(b)). Inthe 1985 proposed Offshore Guidelines,(50 FR 34592, 34617-19, Aug. 26, 1985),EPA proposed special definitionsapplicable to new sources in theoffshore subcategory which areconsistent with 40 CFR 122.29 and


Federal Register I Vol. 58, No. 41 / Thursday, March 4, 1993 / Rules and Regulations

which provide that 40 CFR 122.2 and122.29(b) shall apply "Except asotharwise provided in an applicablenew source performance standard." See49 FR 38046 (Sept. 26, 1984).

Section 306(a)(2) of the CWA defines"new source" 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 adischarge of pollutants" and"construction" to mean "any placement,assembly, or installation of facilities orequipment * * * at the premises wheresuch equipment will be used."

The regulations at 40 CFR 122.2implementing this provision state inpart:

"New Source means any building,structure, facility, or installation from whichthere is or may be a 'discharge of pollutants,'the construction of which is commenced:

(a) After promulgation of standards ofperformance under section 306 of CWAwhich are applicable to such source, or

(b) After proposal of standards ofperformance in accordance with section 306of CWA which are applicable to such source,but only if the standards are promulgated inaccordance with section 306 within 120 daysof their proposal."

The regulations at 40 CFR 122.29(b)(4)state:

"(4) Construction of a new source asdefined under 40 CFR 122.2 has commencedif the owner or operator has:

(i) Begun, or caused to begin as part of acontinuous on-site construction program:

(A) Any placement assembly, orinstallation of facilities or equipment; or

(B) Significant site preparation workincluding clearing, excavation or removal ofexisting buildings, structures or facilitieswhich is necessary for the placement,assembly, or installation of new sourcefacilities or equipment; or

(ii) Entered into a binding contractualobligation for the purchase of facilities orequipment which are intended to be used inits operation with a reasonable time. Optionsto purchase or contracts which can beterminated or modified without substantialloss, and contracts for feasibility engineering,and design studies do not constitute acontractual obligation under the paragraph."(emphasis added).

EPA has developed an interpretationof "new source" that will apply to theoffshore subcategory that the Agencybelieves is reasonable and effectuatesthe intent of the CWA and EPA'sregulations defining new sourcesgenerally. In the final rule, EPA intendsto follow the approach first proposed in1985, in which EPA proposed to define,for purposes of the Offshore Guidelines,"significant site preparation work" as"the process of clearing and preparing

an area of the ocean floor for purposesof constructing or placing adevelopment or production facility on orover the site." (emphasis added). Thus,development and production facilitiesat a new site would be new sourcesunder the Offshore Guidelines. Further,with regard to 40 CFR 122.29(b)(4)(ii),EPA stated that although it was not"proposing a special definition of thisprovision believing it shouldappropriately be a decision for thepermit writer," EPA suggested that thedefinition of new source includedevelopment or production facilitieseven if the discharger entered into acontract for purchase of facilities orequipment prior to publication, if nospecific site was specified in thecontract. Conversely, EPA suggestedthat the definition of new sourceexclude development or productionfacilities if the discharger entered into acontract prior to publication and aspecific site was specified in thecontract. In the final rule, EPA alsointends to follow this approach.

As a consequence of the proposeddefinition of "significant sitepreparation work," if "clearing orpreparation of an area for developmentor production has occurred at a siteprior to the publication of the NSPS,then subsequent development andproduction activities at that site wouldnot be considered a new source." (See50 FR 34618) Also, explorationactivities at a site would not beconsidered significant site preparationwork; therefore, exploratory wellswould not be new sources in anycircumstance. (50 FR 34618)Exploration operations are short term,typically lasting only three to sixmonths (as weather and climate anddrilling conditions allow), whiledevelopment and production operationsoccur over a much longer timeframe.The Agency does not considerexploratory activities to be "significantsite preparation work" because suchactivities are not necessarily followedby development or production activityat a site. Even when exploratory drillingleads to development and productionactivities, the latter may not becommenced for months or years afterthe exploratory drilling is completed.The purpose of distinguishing betweenexploratory drilling and significant sitepreparation for production anddevelopment operations Is to"grandfather" as an existing source anysource if "significant site preparationwork," * * * "evidencing an intent toestablish full scale [development or

roduction] operations at a site, hadeen performed prior to NSPS becoming

effective." (50 FR 34618) At the sametime, if only exploratory drilling hadoccurred prior to NSPS becomingeffective, then subsequent drilling andproduction activities would make thefacility a new source.

EPA also proposed a specialdefinition for "site" in the phrase"significant site preparationwork" usedin 40 CFR 122.2 and 40 CFR 122.29(b)."Site" is defined in 40 CFR 122.2 as"the land or water area where any'facility or activity' is physically locatedor conducted, including adjacent landused in connection with the facility oractivity." EPA proposed that the term"water area" mean the "specificgeographical location where theexploration, development, orproduction activity is conducted,,including the water column and oceanfloor beneath such activities. Therefore,if a new platform is built at or movedfrom a different location, it will beconsidered a new source when placed atthe new site where its oil and gasactivities take place. Even if theplatform is placed adjacent to anexisting platform, the new platform willstill be considered a 'new source,'occupying a new 'water area' andtherefore a new site." [50 FR 34618(Aug. 26, 1985)].

As a consequence of thesedistinctions, exploratory facilitieswould always be existing sources.Production and development facilitieswhere significant site preparation hasoccurred prior to the effective date ofthe Offshore Guidelines would also beexisting sources. These same productionand development facilities, however,would become "new sources" under theproposed regulatory definition if theymoved to a new water area to commenceproduction or development activities.The proposed definition, however,presents a problem because even thoughthese facilities would be "new sources"subject to NSPS, they could not becovered by an NPDES permit in theperiod immediately following theissuance of these regulations. This isbecause no existing permits could haveincluded NSPS until NSPS werepromulgated.

To resolve this problem, the final ruletemporarily excludes from thedefinition of "new source" (pendingEPA's issuance of appropriate permitscovering these facilities) newdevelopment and production facilitiesthat would otherwise be "new sources"if, as of the effective date of the OffshoreGuidelines, the facilities are subject to.an existing NPDES permit. EPA believesthis approach is reasonable becausewhen Congress enacted section 306 ofthe CWA it did not specifically address

12457



mobile activities of the sort common inthis industry, as distinguished fromactivities at stationary facilities on landthat had not yet been constructed priorto the effective date of applicable NSPS.Moreover, EPA believes that Congressdid not intend that the promulgation ofNSPS would result in stopping all oiland gas activities which would havebeen authorized under existing NPDESpermits as soon as the NSPS arepromulgated.

While the situation of mobile oil andgas facilities is rather unique, EPA faceda similar issue in its effluent limitationsguidelines for the placer miningindustry. Placer mines are also mobile,generally moving downstream orupstream. In that effluent guideline, 40CFR 440.144(c), EPA set forth a numberof factors that the RegionalAdministrator or Director of a stateprogram with authority to administerthe NPDES program should take intoaccount in making a case-by-casedetermination of whether a placer mineconstitutes a "new source." Three ofthese factors relate to whether the minewould operate in an area which iscovered by a valid NPDES permit.(Another factor was whether the minesignificantly alters the quantity ornature of pollutants discharged.) TheUnited States Court of Appeals for theNinth Circuit upheld this approach."We find that the criteria set forth onwhat is a new-source placer mine arewithin the ambit of authority whichCongress gave the EPA in the CleanWater Act and cannot be consideredarbitrary or capricious." Rybachek v.U.S. E.P.A., 904 F.2d 1276, 1293 (9thCir. 1990).

Now that NSPS are promulgated, EPAwill apply NSPS to appropriate facilities(i.e., those where there is significant sitepreparation work for development orproduction after promulgation of NSPS)within the Offshore Subcategory. EPAnotes that BAT limitations are equal toNSPS in this rule. EPA intends to issuenew source NPDES permits coveringproduction and development facilitiesas soon as possible.

2. Industry ProfileExisting Platforms (BAT/BCT): EPA's

industry profile estimates includestructures that would incur costs underthis rule. The estimate of existingstructures includes only those platforms(1) in production, (2) with specificproducts (i.e., oil, gas, or both), (3) witha specific number of wells drilled or inproduction, (4) discharging, and (5) inthe offshore subcategory. Two majorsources of data were used to develop aprofile of offshore oil and gas activitiesin the Gulf of Mexico (GOM). In the

March 1991 proposal, EPA used the"Minerals Management Service (MMS)Platform Inspection System, Complex/Structure Data Base" to estimate thenumber of structures in the federalwaters of the Gulf of Mexico that arelikely to bear compliance costs underthis rule. This estimate of 2,233 existingstructures in the Gulf of Mexico (GOM)federal waters remains unchanged. Alimitation of the March 1991 profile wasthat it lacked sufficient data regardingactivities in state waters of the GOM. Tofill this data gap and in response tocomments received, EPA conducted amapping effort to identify structures inproduction in state waters. Using mapsand electronic data, EPA (1) identifiedwells whose well-head location layseaward of the baseline that separatesthe coastal and offshore subcategories;(2) identified wells belonging tocommon platforms; and (3) verifiedwhich wells were still in production. Asa result of this effort to update theindustry profile, an additional 284structures were identified in GOM statewaters. For the Pacific, 32 structures areincluded in the BAT/BCT count ofexisting structures. There are nostructures in the Atlantic at this time.Structures off Alaska in Cook Inlet arein the coastal subcategory and are notaffected by this rulemaking. Currently,there is only one existing facility inAlaskan waters that is seaward of theinner boundary of the territorial seas.This facility is already required by Staterequirements to reinject produced waterand incremental compliance costsassociated with this rule are minimal.No existing Alaskan structures areprojected to incur significantincremental compliance costs under thisrule. A total of 2,549 offshore structuresis used in the BATIBCT economicimpact analysis.

Future Drilling Projections (BA T/BCTand NSPS): Offshore drilling efforts varyfrom year to year depending on suchfactors as the price and supply of oil.the amount of state and federal leasing,and reservoir discoveries. EPA estimatesfuture drilling activity averaging 759wells per year during the 15-yearperiod, from 1993-2007, afterpromulgation of this regulation.Estimated activity in the Gulf of Mexicoand Alaska are based on MMS 30-yearregionalized forecasts with an averagebarrel of oil equivalent (BOE) price of$21/bbl (1986 dollars) for the 15-yearperiod. The drilling projectionspresented in the 1991 proposal for theGulf of Mexico and Alaska were basedon a 1986-2000 time frame. Moving thestarting year forward for the 15-yearperiod, from 1986 to 1993, resulted in

about a three percent change in thenumber of wells from the original set ofprojections (i.e., slightly higher if basedon the year 1990, slightly lower forprojections beginning in 1993). Becausethe projection of estimated futureactivity does not change significantly bystarting in 1992 rather than in 1986,EPA is using its projections beginning in1986. Recent Presidential moratoriahave prevented offshore activities incertain areas in the Eastern Gulf ofMexico, but this is not expected to causea significant change in the regionalestimate of future activity.

Recent moratoria and restrictedleasing in the Pacific constrain drillingestimates to the level of activityassociated with drilling on installedstructures and existing leases. Due tothe Presidential decision to cancel leasesale 96 (Georges Bank region in theNorth Atlantic) and strictly limit anyactivity in this planning area until afterthe year 2000, no activity is projectedfor the Atlantic during the 1986-2000time period. (EPA is aware of one siteoff the coast of North Carolina where anoperator has expressed interest indrilling.) EPA anticipates that theserestrictions will remain applicable untilafter the year 2007. This set ofprojections corresponds to the"restricted" or "constrained" wellforecast presented in the March 1991proposal.

The projection of 759 wells drilledper year includes all new well-productive, non-productive (dry holes),exploratory, and development. The newwell projections therefore include bothBAT and NSPS wells. As explainedabove, BAT wells encompassexploratory wells in addition todevelopment and production wells forwhich significant site preparation takesplace prior to promulgation of theregulation. NSPS wells are drilled onplatforms where significant sitepreparation and installation take placeafter promulgation of the regulation.Table I is a summary of the BAT andNSPS wells by region. Approximatelyone-third of the new wells may beconsidered existing sources. (The actualpercentage of wells classified as existingsources will vary in time. Most will beexploratory efforts. The number of newwells drilled on existing platforms willdecrease in time as those platformscomplete their drilling programs. Thenumbers given in Table I reflect theannual average number of wells duringthe 15-year period followingpromulgation of the regulation.)



TABLE 1.-AVERAGE ANNUAL NEW WELLDRILLING1wals/yearl

ExIsting NewRegion sources sources Total

(BAT) (NSPS)

Guf ........... 215 500 715Pacific ....... 32 0 32Alaska .3 9 12

Total.. 250 509 759

New Platforms: Platform projectionswere made based on the number ofproductive wells. An estimated total of759 platforms will be installed duringthe 15-year period after promulgation ofthe regulation. The fact that theestimated average annual number ofwells (759) is the same as the totalnumber of platforms (759) installedduring the 15-year period iscoincidental.

C. Waste StreamsThe primary wastewater sources from

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

" Drilling fluids." Drill cuttings." Sanitary wastes." Deck drainage." Domestic wastes.The primary wastewater sources from

the production phase of the industryinclude the following:

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

workover fluids.Drilling fluids (typically termed

muds) and drill cuttings are the mostsignificant waste streams fromexploratory and development operationsin terms both of volume and toxicpollutants. Produced water is the largestwaste stream from production activitiesbased on its volume of discharge andquantity of pollutants. Deck drainage,sanitary wastes, domestic wastes,produced sand, and well treatment,completion, and workover fluids areoften classified under the termmiscellaneous wastes.

Drilling fluids are any fluid sent downthe drillhole to aid the drilling process.This includes those materials used tomaintain hydrostatic pressure control inthe well, lubricate the drill bit, removedrill cuttings from the well, andstabilize the walls of the well duringdrilling or workover operations. Awater-based drilling fluid is theconventional drilling system in whichwater is the continuous phase. Drill

cuttings are the solids generated bydrilling into subsurface geologicformations and are carried to the surfaceby the drilling fluid system.

Produced water is brought up fromthe hydrocarbon-bearing strata alongwith produced oil and gas. This wastestream can include formation water,injection water, and any chemicals(including well treatment, completionor workover fluids) added downhole orduring the oil/water separation process.

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

Well treatment fluids are fluids thatresurface from acidizing and/orhydraulic fracturing operations toimprove hydrocarbon recovery.Workover fluids and completion fluidsare low solids fluids used to prepare awell for production, provide hydrostaticcontrol, and/or prevent formationdamage.Produced sand consists of the slurried

particles which surface from hydraulicfracturing and the accumulatedformation sands and other particles(including scale) generated duringproduction. This waste stream alsoincludes sludges generated in theproduced water treatment system, suchas tank bottoms from oil/waterseparators and solids removed infiltration.

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

EPA presented detailed discussions ofthe origins and characteristics of thewastewater effluents from exploration,development, and production in theMarch 13, 1991 proposal. EPA generallyfocused data gathering efforts and dataanalyses on drilling fluids, drillcuttings, and produced water due totheir volumes and potential toxicity.Information on the miscellaneouswastes is more limited. Their volumesare generally smaller, and in most casesare either infrequently discharged or arecommingled with the major wastestreams. However, EPA has determinedthat it is appropriate to promulgateregulations for miscellaneous wastes aswell.IV. Development of the FinalRegulation

On September 15, 1975, EPApromulgated interim final BPT effluentlimitations guidelines (40 FR 42543)and proposed BAT and NSPSregulations (40 FR 42572) for theoffshore subcategory of the oil and gasextraction point source category("offshore subcategory"). EPA

promulgated final BPT regulations onApril 13, 1979 (44 FR 22069), butdeferred action on the BAT and NSPSregulations. Table 2 presents the 1979BPT limitations.

The Natural Resources DefenseCouncil (NRDC) filed suit on December29, 1979 seeking an order to compel theAdministrator to promulgate final NSPSfor the offshore subcategory. Insettlement of the action (NRDC v.Castle, C.A. No. 79-3442 (D. D.C.)(JHP)),EPA acknowledged the statutoryrequirement and agreed to take steps toissue such standards. However, becauseof the length of time that had passedsince proposal, EPA believed thatexamination of additional data andreproposal were necessary.Consequently, EPA withdrew theproposed NSPS on August 22. 1980 (45FR 56115). The proposed BATregulations were withdrawn on March19, 1981 (46 FR 17567).

On August 26, 1985 (50 FR 34592)EPA proposed BAT and BCT effluentlimitations guidelines and new sourceperformance standards for the offshoresubcategory. The 1985 proposal alsoincluded an amendment to the BPTdefinition of "no discharge of free oil."The waste streams covered by the 1985proposal were drilling fluids, drillcuttings, produced water, deck drainage,well treatment fluids, produced sand,and sanitary and domestic wastes.

TABLE 2.-BPT EFFLUENT UMITATiONS(PROMULGATED 1979)

Waste stream Parameter BPT effluentlimitation

Produced water Oil and grease 72 mg/I dailymaximum.

... 48 mgI 30-dayaverage.

Drilling fluids Free oil ........ No di 'arge.Drill cut s Free oil ......... No discharge.Well treatment Free oil. No discharge.

fluids.Deck drainage Freeoll .......... No discharge.SaNltary-"10 :... Residual chlo- 1 mg/I. (rini-

Fine. mum.)Sanftary-M91M.. Floating solids. No discharge.

On October 21, 1988, EPA issued aNotice of Data Availability (53 FR41356) concerning the development ofNSPS, BAT, and BCT regulations for thedrilling fluids and drill cuttings wastestreams (the "1988 notice"). The 1988notice presented substantial additionaland revised technical, cost, economic,and environmental effects informationwhich EPA collected after publication ofthe 1985 proposal. EPA presented newinformation regarding the diesel oilprohibition and the toxicity limitation,and new compliance costing andeconomic analysis results based on newprofile data and treatment and control

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option development. The new controltechnologies discussed were based onthermal distillation, thermal oxidation,and solvent extraction. Performancedata for these technologies were alsoincluded. In addition, EPA proposedrequirements for limitations on metalscontent in the stock barite based on theuse of existing barite supplies, oralternatively in the drilling fluids(whole fluid basis) at the point ofdischarge.

On January 9, 1989, EPA published aCorrection to Notice of Data Availability(54 FR 634) concerning the analyticalmethod for the measurement of oilcontent and diesel oil. The 1988 noticehad inadvertently published anincomplete version of that method.

On November 26, 1990, EPApublished a notice and a reproposal (55FR 49094) that presented the major BCT,BAT, and NSPS regulatory optionsunder consideration for control ofdrilling fluids, drill cuttings, producedwater, deck drainage, produced sand,domestic and sanitary wastes, and welltreatment, completion, and workoverfluids. On March 13, 1991 (56 FR10664), EPA published a second noticeproposing BAT, BCT, and NSPSlimitations and standards for theoffshore subcategory. The regulatoryoptions presented were the same asthose proposed on November 26, 1990with the exception of deleting arequirement under NSPS whichprohibited the discharge of visible foamfrom the sanitary wastestream (therequirement had been inadvertentlyincluded in the November 1990proposal).

The 1990 and 1991 proposals did notsupersede the 1985 proposal entirely.Rather, they revised the 1985 proposalin certain areas. The revisions werebased on new data and informationacquired by EPA since the 1985proposal regarding wastecharacterization, treatment technologies,industrial practices, industry profiles,analytical methods, environmentaleffects, costs, and economic impacts.Some of this new information regardingdrilling wastes had been published in aNotice of Data Availability (53 FR41356) (October 21, 1988). This newinformation led EPA to developadditional regulatory options to thoseproposed in 1985.

On April 5, 1991 (56 FR 14049) EPApublished notification of publicworkshops for the guidelines proposedon March 13, 1991, and extended thecomment period for the proposed rule.The comment period for the majority ofthe rule was extended by 30 days. Thecomment period for membrane filtration

and radioactivity issues was extendedby 60 days, and ended on June 11, 1991.

The Consent Decree was again revisedon May 28, 1992. Under thismodification, the date for promulgationof the final effluent limitationsguidelines and standards (BUtr, BAT,and NSPS) for produced water, drillingfluids and drill cuttings, well treatmentfluids, and produced sand wastestreamswas extended from June 19, 1992 toJanuary 15, 1993.

Ocean discharge criteria applicable tothis industry subcategory werepromulgated on October 3, 1980 (45 FR65942) under section 403(c) of the Act.These guidelines are to be used inmaking site-specific assessments of theimpacts of discharges. Section 403limitations are imposed through section402 National Pollutant DischargeElimination System (NPDES) permits.Section 403 is intended to preventunreasonable degradation of the marineenvironment and to authorizeimposition of effluent limitations,including a prohibition of discharge, ifnecessary, to ensure this goal.

In addition, EPA has issued a seriesof general NPDES permits that set BATand BCT limitations applicable tosources in the offshore subcategory on aBest Professional Judgment (BPJ) basisunder section 402(a)(1) of the CleanWater Act. See e.g., 57 FR 54642(November 19, 1992) (Western Gulf ofMexico OCS General Permit); 51 FR24897 (July 9, 1986), (Gulf of MexicoOCS General Permit); 49 FR 23734 (June7, 1984), modified 52 FR 30481(September 29, 1987) (Bering andBeaufort Seas General Permit); 50 FR23570 (June 4, 1985) (Norton SoundGeneral Permit); 51 FR 35400 (October3, 1986) (Cook Inlet/Gulf of AlaskaGeneral Permit); 53 FR 37840(September 20, 1988), modified 54 FR39574 (September 27, 1989) (BeaufortSea II/Chukchi Sea General Permits).The rulemaking record for this final ruleincludes copies of the most significantFederal Register notices proposingthese general permits and issuing themin final form.

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

V. Major Changes to the Data Base forthe Final Regulation

This section describes several of themost significant changes to themethodology and data base which haveoccurred since the proposals. Otherareas of change and issues are discussedin other sections of this preamble, theDevelopment Document, the EconomicImpact Analysis, the Regulatory ImpactAnalysis, and the record for this rule.

A. Drilling Fluids and Drill Cuttings

1. Engineering Costs

a. BAT and NSPS CostingMethodology. The costing methodologyfor the final rule is based on the costingmethodology presented in the March 13,1991 proposal. However, EPA improvedthe database and sought additionalconfirmatory data in response tocomments on the proposal. Asdiscussed in the March 1991 proposal,EPA created a database and computermodels to generate regionalized costingestimates for the handling and ultimatedisposal of spent drilling fluids anddrill cuttings. The database consists ofthe following elements:

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

* Characteristics of a "model well"describing average values for parameterssuch as well depth, volume of wasteassociated with drilling activity, use ofadditives to aid in drilling, and lengthof time to drill a well.

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

* Failure rates of drilling wastes withrespect to compliance tests for certaindischarge limitations (e.g., static sheen,toxicity).

* Compliance costs, includinganalytical costs and disposal costs fortransportation and land disposal ofdrilling wastes.

The data were entered into thecomputer models designed to predictregionalized compliance costs andpollutant removals for the variousregulatory options considered. Ananalysis of each option was conductedto determine:

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

with the regulation• Volume and percent of drilling

waste requiring onshore disposal* Direct and incidental pollutant

removalNo distinction was made between the

BAT and NSPS wells for compliancecosting because of the negligibledifferential in drilling fluids and drill


Federal Register / Vol. 58, No. 41 1 Thursday, March 4, 1993 / Rules and Regulations

cuttings compliance costs between anew well drilled as an existing sourceand one drilled as a new source. ForBAT and NSPS, the computer modelsidentified costs and pollutant removalswhich were incremental beyond whatwas required for "current" levels ofcontrol. Current control levels reflectedexisting NPDES permit requirementsthat EPA considered representative ofcontrol measures in practice. Thecurrent requirements were (and are)often more stringent than BPT.

b. Costing Assumptions. In projectingcompliance costs, EPA made severalassumptions about the current drillingpractices to characterize the industry.These assumptions were based onAgency-sponsored analyses, industry-sponsored analyses, and publiccomments from previously publishedproposals or notices of data availability.Several assumptions presented in therulemaking record as part of the March13, 1991 proposal have been updateddue to further investigation by EPA orthrough submission of additional datain public comments. EPA's reevaluationof costing assumptions has led to areduction in barite usage volumes,barite substitution costs, onshoredisposal volumes, and onshore disposalcosts. The following paragraphs discussthe manner in which assumptionspresented in previous costing estimateshave been revised for the final rule,

The estimated volume of drillingfluids and drill cuttings generated havechanged slightly due to revisions incalculations of: the average well depth,the deep well depth, and the percentageof wells greater than the average welldepth. The determination of thevolumes of drilling fluids and drillcuttings generated is still based on dataand the methodology presented by theOffshore Operators Commitee reportentitled "Alternate Disposal Methodsfor Muds and Cuttings: Gulf of Mexicoand Georges Bank," December 7,1981.EPA revised the average model welldepths, the deep well depths, and thepercentage of wells greater than theaverage well depth to include welldepth data from the API JointAssociation Survey on Drilling Costs fora period of five years, The well depthdata used for the March 1991 proposalwas based on one year of data. Therevised average well depths for themodel wells are as follows: 10,559 feetin the Gulf of Mexico, 7,607 feetoffshore California, and 10,633 feetoffshore Alaska.

Since deep wells (those greater than10,000 feet in depth) require larger boreholes and thus generate greater wastevolumes, it is important to consider thefrequency of drilling deep wells.

Industry drilling data were used torevise estimates of the typical deep welldepths as follows: 13,037 feet in theGulf of Mexico, 10,081 feet offshoreCalifornia, and 12,354 feet offshoreAlaska. The proportion of wells drilleddeeper than 10,000 fot was alsorevised. At proposal, EPA assumed that30.8% of all wells would be deeper than10,000 feet and that percentage wasused for all regions. Based on dataevaluated for this-final rule. EPA revisedestimates of the proportion of deepwells as follows: 49 percent in the Gulfof Mexico, 42 percent off California, and59 percent off Alaska. At proposal, EPAused the waste volumes generated bymodel wells to estimate onshoredisposal requirements. In reassessingthese estimates, EPA made a distinctionbetween the waste volumes generatedfrom model wells and deep wells tomore accurately characterize pollutantremovals and onshore disposalrequirements.

]n the March 1991 proposal, EPAassumed that all deep wells used amineral oil-based drilling fluid for thatfootage drilled deeper than 10,000 feet.Several industry commenters and atrade association stated that fifteenpercent (15%) is a more representativeestimation of the oil-based mud usagefor deep well projects, and providedEPA with recent data on usage of oil-based drilling fluids. Upon review ofthis data, EPA revised its computermodel to assume fifteen percent of allwells drilled deeper than 10,000 feetwould utilize an oil-based drilling fluid.The application of this assumptionprojects a lower volume of drillingwaste requiring onshore disposal. Theprevious estimates assumed that alldrilling wastes generated deeper than10,000 feet would require onshoreproposal due to noncompliance with thefree oil and toxicity limitations.However, the decrease in onshoredisposal volumes based on newinformation is offset by the new

-information about greater numbers ofdeep wells and greater volumes fromdeep wells due to larger bore holediameters.

Since proposal, EPA also revised itsassumptions about the characteristics ofthe type of drilling fluids (or "muds")used, e.g., density of drilling fluids. Inevaluating comments which disputedpollutant removal estimates for drillingwastes, EPA revised its assumptionsabout the mud compositions. Themethodology used in the proposalattempted to characterize the drillingfluids used in different portions of thewell based on drilling depth, lubricity,and type of mud (water-based or oil-based). In the March 1991 proposal,

EPA made assumptions regarding bariteuse which were equivalent to the bariteconcentration in a relatively highdensity (18 pound per gallon) drillingfluid. Since proposal, EPA has learnedthat such high density drilling fluids aregenerally used only at deep well depthsor for unusual circumstances, and theyare not considered representative of themud systems typically used in offshoredrilling projects. Also. EPA'sreevaluation of the metals loadingsderived from the previous mudcompositions revealed incomplete massbalances-with the barite volumes in themuds and the barium concentrations inthe metals database. (In other words, the-amount of barite in drilling fluids didnot correspond to the measured bariumconcentrations in the discharge ofdrilling fluids and drill cuttings.) Toalleviate these inconsistencies, tosimplify the costing model, and tocharacterize more accurately the drillingfluids used by the industry, EPA revisedthe estimated mud compositions to thatof a drilling fluid with an averagedensity of 11 pounds per gallon (ppg)based on a review of dischargemonitoring report data andcommunications with industry sources.EPA considers the 11 ppg mud to berepresentative of a typical drillingprogram that includes low density mudsused for the initial stages of drilling, andthe medium to heavy density muds usedtowards completion at the bottom of thewell. The net result of this revisedassumption is a reduction in estimatesof barite usage, barite substitution costs,and pollutant removals for the drillingfluids and drill cuttings.

In concert with revising the drillingfluid composition, EPA revised the datacharacterizing the metals content inbarite to more closely represent thecomposition of a typical drilling fluid.Barite is used as a weighting agent toassist in controlling downhole pressure.EPA derived updated metalsconcentrations in drilling fluids from astatistical analysis of the API/USEPAMetals Database. This database, fromseveral sampling programs conductedby EPA and the industry, contains end-of-pipe metals concentrations in drillingfluids. EPA presented these data in therulemaking record for the March 13,1991 proposal. The metals data setincludes additional elements that EPAdetermined to be of significantoccurrence, concentration and toxicity.In addition to the priority pollutantspresented in 56 FR 10699, EPAestimated removals for aluminum, iron,tin, and titanium.

The revised costing estimates alsoinclude updated regionalized onshoredisposal costs. The onshore disposal

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costs presented in the March 1991proposal consisted of one set of disposalcosts for all geographical regions. In thereevaluation of the costing assumptions,EPA distinguished between costs forvarious geographic regions, namely theGulf of Mexico, California, and Alaska.

Additional requirements placed onOCS sources under the recentlypromulgated air regulations for OCSsources (57 FR 40792; September 4,1992) were considered in developingcompliance costs for this rule.Emissions offset costs were calculatedfor all wells drilled off California, sincethis OCS planning area is adjacent to anonshore nonattainment area. Offset costsare assumed to be an annual expenseand are included in the annual costs forthe drilling fluids and drill cuttingsoptions. Offset costs were calculated fornitrogen oxide and hydrocarbonemissions were calculated for thisregulation based on annual costs of$15,000 per ton of nitrogen dioxide and$5,000 per ton of hydrocarbons.2. Drilling Waste Pollutant Loadings

In projecting pollutant reductionsresulting from this rule, EPA used anexpanded data set some of which,although included in the rulemakingrecord at proposal, had been receivedtoo late to be included in the pollutantloadings analysis related to the metalscontent in drilling fluids. The updatedmetals concentrations were derivedfrom a statistical analysis of the API/USEPA Metals Database. These datawere obtained from several samplingprograms sponsored by EPA andindustry and represent end-of-pipemetals concentrations of drilling fluids.In addition to the priority pollutantsused in loadings for the proposal, thepollutant loadings used for the final ruleinclude aluminum, iron, tin, andtitanium.

EPA also updated the pollutantloading estimates for drill cuttings. Inthe proposal, EPA based its loadings onestimates of barite concentration in thedrill cuttings. In evaluating loadings forthe final rule, EPA determined thatprevious estimates of 88 pounds ofbarite per barrel of drill cuttings wereoverestimates. The revised pollutantloading estimates for drill cuttings inthis rule are based on the pollutantspresent in the drilling fluid adhering tothe cuttings. Five percent, by volume, ofdrilling fluid adheres to drill cuttingsafter separation.

EPA's revision of the assumptions ondrilling fluid composition also reducedestimates of the total suspended solid(TSS) content of the drilling fluids. TheTSS concentration of the averagedrilling fluid density (11 ppg) serving as

the basis for the projections for this ruleis less than that of the higher densitydrilling fluid previously modeled in the1991 proposal.

B. Produced Water

1. Gas Flotation PerformanceEPA received additional data on

performance of gas flotation technologyin response to the 1991 proposal. Theimproved gas flotation technology basisfor the produced water limitationsconsidered for this final rule includesutream gravity separation and

mical addition. This sectionsummarizes these additional data andEPA's analysis, and presents limitationsbased on EPA's analysis.

Data available for this analysisincluded those collected for the EPA's30 Platform Study (1981), the OffshoreOperators Committee's (OOC) 42Platform Study (1990), the OOC's 83Platform Composite Study (1991), andEPA's "Oil Content in Produced Brineon Ten Louisiana Production Platforms"(1981).

For the EPA's 30 Platform Study, OOCmember platforms were selected basedon characteristics such as widegeographical distribution, type ofproduction, ownership of the facility,and other non-random considerations.Seven of these thirty platforms usedgravity separation and chemicaladdition followed by gas flotation totreat their produced water. All oil andgrease measurements were made usingEPA Method 413.1, a process formeasuring total oil andgrease. Grabsamples of influent and effluent weremeasured.

For the OOC's 42 Platform Study,OOC member platforms were selected.The study was statistically designed toestimate within-process variation andlaboratory variation. However, thesampling procedures used in the studyinflate the estimated laboratoryvariation with some sampling variation.Total oil and grease-measurements weremade using Method 413.1. Grab samplesof effluent were taken according to abalanced statistical design.

For the OOC's 83 Platform CompositeStudy, data from four studies werecombined. These four studies includeEPA's 30 Platform Study, OOC's 42Platform Study, OOC's 10 PlatformDatabase, and OOC's 12 PlatformRefrigeration Study. The two additionalOOC studies were designed in a fashionsimilar to that used for OOC's 42Platform Study. All of the platforms inthe OOC studies are described asconforming to specifications, operatingproperly, and adding chemicals asneeded. All oil and grease

measurements considered here wereperformed using Method 413.1 on grabsamples of effluent. Again, the samplingprocedures used inflate the laboratoryvariation estimate with some samplingvariation.

For the EPA's "Oil Content inProduced Brine on Ten LouisianaProduction Platforms," platforms wereselected based on size, technologydifferences, and availability of livingand working space. Grab samples ofinfluent and effluent were measured foroil and grease by early methods for totaloil and grease, insoluble oil and grease,and soluble oil and grease. Detailedinformation regarding the treatmentsystem is summarized in the studyreport. Samples were taken according toa balanced statistical design.

All available oil and grease data forimproved gas flotation, as measured byMethod 413.1 were considered inestablishing the limitations in the finalrule. After screening platforms forcompliance with current BPTlimitations, EPA applied statisticalmethods to the data in order to calculatethe long-term average concentration ofoil and grease for use as the basis of thelimitations. Then EPA calculatedpercentiles which express therelationship between the long-termaverage performance and the variabilityto be expected at a well-designed,operated, and maintained platform. Thedaily maximum limitation is set suchthat there is a 99 percent probabilitythat a physical composite sample takenfrom the median performing platformwill have total oil and greasemeasurements less than or equal to thatconcentration. Each physical compositeis composed of four grab samples takenduring a single day. The monthlyaverage limitation is set such that thereis a 95 percent probability that amonthly average of physical compositesamples taken from the medianperforming platform will have total oiland grease measurements less than orequal to that concentration. Themonthly average is the arithmeticaverage of four physical compositesample results collected during thesame month (during a 30 dayconsecutive period). These percentilescorrespond to large effluent values thatwould rarely be exceeded by a well-operated treatment system andrepresents levels that are achievable atall times under normal operatingconditions.

The daily maximum limitation fortotal oil and grease not to be exceededis a concentration of 42 mg/I and themonthly average limitation not to beexceeded is a concentration of 29 mg/l.Note that the addition of new data and



the modification of the methodology forapproximating percentiles for compositesamples measurements based on grabsample measurements, each done inresponse to comments, has not greatlychanged the Agency's estimate of whatlimitations would be appropriate basedon this technology. In the 1991proposal, EPA presented a dailymaximum limitation of 38 mg/i andmonthly average limitation of 27 mg/Ibased on this technology.

2. Produced Water Engineering CostsThe costing methodology for

produced water in the final rule is thesame as the methodology for producedwater presented in the March 13, 1991proposal. However, EPA made severalchanges to the database due tocomments on the proposal and afterEPA conducted further analysis of theindustry. As discussed in the proposal,EPA created a database and developedcomputer models to generateregionalized costing estimates for thetreatment and disposal of producedwater. The database consisted of thefollowing elements:

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

9 Projected future productionactivity.

* Produced water contaminanteffluent levels associated with BPTtreatment and with BAT and NSPStreatment options.

* Cost to implement the BAT andNSPS treatment technology options.

Using the data and the computermodels, EPA predicted regionalizedcompliance costs and pollutantremovals for the various regulatoryoptions as defined in section XIII of thisNotice. These options are comprised ofthree potential treatment technologiesfor BAT and NSPS; the three treatmenttechnologies are:

* Improved operating performance ofgas flotation technology.

* Granular filtration and subsequentsurface water discharge.

* Granular filtration followed byreinjection of the produced water intoany compatible geologic formation.

Similar to the costing methodology forthe proposal, the per-platform capitalcosts for the treatment equipment andthe associated annual operating,maintenance and monitoring costs(annual costs) were developed formodeled treatment systems with designcapacities of 200 barrels per day (bpd),1,000 bpd, 5,000 bpd, 10,000 bpd, and40,000 bpd of produced water. EPAderived costs for these systems based onvendor-supplied data, industryinformation, and cost analyses

conducted by the Energy InformationAdministration of the Department ofEnergy (DOE/EIA). Curves depictingflow rate versus cost were generated toestimate the capital and annual costs fortreatment systems with capacities otherthan the five modeled systems for whichcost data were collected.

EPA calculated total industry costs foreach treatment option using the per-platform capital and annual costs andindustry profiles of current andprojected future production activity inthree geographical offshore areas, theGulf of Mexico, California, and Alaska.EPA did not develop specific industrycosts for the Atlantic offshore areas,including Florida, because of the lack ofoil and gas leasing and development inthese areas. However, the costs in theseregions are considered similar to thosedeveloped for offshore Californiabecause conditions in these areas aremore analogous to California than to theGulf. Because of the extensive amountof activity in the Gulf of Mexico, costsof offshore operations in the Gulf aresomewhat lower than in California. EPAexpects that the amount of any futureactivity in the Atlantic or off the coastof Florida will, at most, approach theamount of activity in California ratherthan the amount of activity in the Gulf.Accordingly, EPA projects that costs forCalifornia are more appropriate forprojecting costs in these other areas.

For each geographical area, EPAcharacterized the industry as apopulation consisting of variousplatform structure types, or modelplatforms. A model platform wascharacterized by the number of availablewell slots on the platform. Eachproducing well is brought to thewellhead on the platform through adedicated well slot. The number of wellslots on a platform indicates themaximum number of producing wells.The model platforms were furthersubdivided based on whether theyproduced: (.1) Oil only; (2) both oil andgas; or (3) gas only.

For each "model platform," EPAestimated the number of producingwells, the quantity of produced watergenerated (average and peak flow), andthe cost to implement a produced watertreatment system. Thus, by dividing theindustry among these "modelplatforms," EPA derived estimates ofcosts and pollutant reductions.

EPA determined contaminantremovals by comparing the estimatedeffluent levels after treatment by theBAT and NSPS treatment systemsversus the effluent levels associatedwith a typical BPT treatment.

The computer model calculated thecapital costs for each model platform in

each region based on the maximumdaily produced water flow rate for thegiven platform. The maximum dailyflow rate for each modeled platformdetermined the required capacity of thetreatment system. Interpolating alongthe "capital cost-flowrate" curvedeveloped for the five modeledtreatment systems, EPA determined thecapital costs for each of the modelplatforms.

The computer model calculated theannual costs for each model platform ineach region based on the average dailyproduced water flow rate for the givenplatform. The average daily flow rate foreach modeled platform was used todetermine the annual costs.Interpolating along the "annual cost-flowrate" curve developed for the fivemodeled treatment systems, EPAdetermined the annual costs for each ofthe model platforms.

a. Gas Flotation System Capital andAnnual Costs. EPA developed gasflotation equipment costs based ondirect contact with vendors andmanufacturers of offshore gas flotationequipment. The packaged equipmentcosts are the costs for the complete gasflotation system which includes thefollowing: a skid-mounted flotationunit, complete electrical system, oil andwater outlets brought to the edge of theskid, and sufficient instrumentation forproper operation.

EPA based gas flotation spacerequirements on information providedby vendors and manufacturers ofoffshore gas flotation equipment. Someexisting (BAT) platforms could incurcosts for additional space such as acantilevered deck. A cantilevered deckor wing deck can be added along oneside of a platform to increase the totalsquare footage of the platform deck. Forexample, a one hundred foot longcantilevered deck that extends ten feetfrom the edge of the existing platformdeck would add one thousand squarefeet to the platform deck, EPA estimatedthe cost of additional platform space at$250 per square foot based oninformation obtained from industry andthe Department of Energy. The actualareas required by the gas flotationsystems were estimated to be twice thearea of the process equipment"footprints" that were furnished by thevendors. The additional area includessufficient space for any additionalprocess equipment, instrumentation,and walkways. For the NSPS scenario,because new facilities can include thegas flotation equipment in the design ofthe platform, EPA determined that noadditional platform space, such as acantilevered deck, would be required.(In cases where new sources would be

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platforms that exist as of the effectivedate of the offshore guidelines, the costof adding platform space has beenaccounted for in costing the BATlimitations for existing sources.) Thismethodology is identical to thatpresented in the proposal for otherproduced water treatment systems.

The annual operating andmaintenance costs for the gas flotationtreatment systems included energycosts, labor costs, and typical operatingand maintenance costs such as polymerand/or flocculation enhancementchemicals or costs for pump and agitatormaintenance and replacement.

b. Granular Filtration Capital andAnnual Costs. The basis for the granularfiltration costing is similar to that of theMarch 13, 1991 proposal. EPA contactedthe DOE/EIA to assist in reevaluatingthe capital and annual costs for granularfiltration systems developed for theproposal. EPA used informationprovided by DOE/EIA. as well asadditional data collected by EPA, toupdate cost projections for granularfiltration systems.

In revising costs, EPA no longerincludes capital costs for chemicalstorage or electrical generators. Capitalcosts associated with the actualchemical injection system are includedin the filtration system capital costs.Storage of chemicals is included as anannual cost. The revised costs alsoexclude previous cost projections forextra generators to provide power tooperate treatment system modifications.The power requirements for thefiltration system (approximately 30horsepower) are minimal in comparisonto the electrical generation capacityavailable on platforms and the existinggeneration capacity is consideredadequate for this minimal powerrequirement increase. The revisedcosting now includes capital costs for acentrifuge to dewater the filterbackwash. Backwash dewatering isnecessary to minimize the spacerequired to store the backwash andminimize the transportation andonshore disposal costs.

The revised costing assumes thatadditional deck space could be added tothe platform for systems treating up to40,000 barrels of produced water perday. This is based on data showing thatfiltration systems treating up to thisvolume could be installed in areas ofless than 1,000 square feet. Onethousand (1,000) square feet is assumed-to be the largest area that can be addedto a platform as a cantilevered deck. Thecosting presented in the March 1991proposal had assumed that all filtrationsystems processing over 5,000 barrelsper day (bpd) would have area

requirements exceeding 1,000 squarefeet and thus would requireconstruction of additional platformstructures. EPA recalculated the arearequirements for this final rule inconsultation with DOE/EIA. Filtrationsystems treating mor than 40,000 bpdare still considered to exceed theavailable space on the platform(including additional capacity from adeck addition), thus construction of aseparate platform structure would berequired.

c. Reinjection Capital and AnnualCosts. Part of the basis for thereinjection costing methodology issimilar to that of the granular filtrationoption since filtiration of the producedwater is typically necessary prior toreinjection. Without this pretreatment,fine solids can plug the pores of theformation, decreasing the capacity of theformation, thus preventing thereinjection of the produced water. Forthis costing estimation, EPA assumedthat multi-media filtration would be thepre-treatment filtration technology used.

The capital costs for pumps andinjection wells were revised to representnew data obtained by EPA. The DOE/EIA developed capital costs for gasturbine injection pumps which reflectmore recent (1991) cost data and areslightly lower than the costs presentedin the proposal. Injection well costswere revised based on data submittedwith industry comments. The costs fornew injection wells remainedapproximately the same as thosepresented in the proposal, but the coststo recomplete an existing dry holechanged significantly. The revisedrecompletion costs increased from$240,000 per well to $675,000 per well.

The revised capital costs for thereinjection option also do not includeadditional costs for electrical generators.Where facilities reinject, gas-powered,rather than electrical, injection pumpsare generally used. Also, construction ofseparate platform structures to containproduced water treatment systemmodifications are not anticipated unlessthe system processes over 40,000 barrelsper day of produced water. Based onEPA calculations made in consultationwith DOE/EIA, area requirements forinjection systems treating less than40,000 bpd are less than 1,000 squarefeet and can be met by constructingplatform additions such as cantilevereddecks.

d. Regional and Total Industry Costs.The regional costs were calculatedbased on the per-platform capital andannual costs and the number ofplatforms within each geographicalregion. For the purposes of determiningproduced water compliance costs for

this rule, EPA assumed that all newlyinstalled production and developmentplatforms would be new sources. EPAwas unable to determine the extent towhich existing platforms would be usedto develop new hydrocarbon reserves.While an existing platform moved to anew location for development or -production would also be classified asa new source, compliance costs for allexisting platforms are included as BATcosts in this rule. Since BAT limitationsare equal to NSPS, to ascribe both BATand NSPS costs of compliance to onefacility would double-count the costs ofcompliance with the rule. Also, EPA isunaware of any existing contractualobligations which could result in newpoduction and development platforms

ing classified as existing sources. Forthis rule, new production anddevelopment platforms are included asnew sources.

Based on information from theDepartment of the Interior and aspresented in the March 1991 proposal,EPA estimated that thirty-seven percent(37%) of existing platforms currentlypipe their produced water to shore fortreatment. Therefore when developingthe regional costs, only sixty-threepercent (63%) of the total number ofexisting platforms and one hundredpercent (100%) of new platforms wereassigned offshore treatment costs.Onshore treatment costs were assignedto those facilities currently piping toshore. Onshore treatment costs aredetailed in section V.B.2.e of thispreamble. EPA cost projections for newplatforms indicate that the cost ofoffshore treatment will be less than thecombined cost of installing piping andestablishing onshore treatment facilities.Thus, EPA assumed all new sources willtreat water offshore. The total industrycosts for the granular filtration and thereinjection option are the sum of theregional costs for each treatment option.

The total capital costs for gas flotationwere more complicated to determinebecause many operators currently usethe gas flotation technology to complywith the current BPT regulations. Toavoid over-costing by assigning capitalcosts to all platforms, EPA predicted thenumber of existing platforms thatcurrently have gas flotation systems andthe number of platforms that will haveto install new flotation systems. Thefollowing paragraphs explain EPA'sbasis for its estimate of the totalindustry costs for the gas flotationoption.

EPA determined that to achieve BAToil and grease limitations based onimproved performance of gas flotationtechnology, operators who currentlyhave gas flotation treatment systems



would continue to use the sametreatment units, although some changesto those systems or their manner ofoperation might be necessary. Forexisting platforms that do not currentlyhave gas flotation systems and can notmeet the limitations of the final rulewith their currently installed treatmentsystems, some form of add-on treatmentwould be necessary. For costingpurposes, EPA assumed that allfacilities currently without gas flotationsystems are unable to meet the BAT (orfor new sources, NSPS) limitations, andthat flotation units would need to beinstalled. This assumption does not takeinto consideration the fact that othertreatment technologies currently usedby the operators are available for use,such as parallel plate coalescers,corrugated plate interceptors,hydrocyclones, or filtration, and theiruse may enable operators to meet therequirements of this rule withoutrequiring installation of flotation units.(The establishment of an effluentlimitation based on a given technologydoes not require use of the treatmenttechnology upon which the limitation isbased.) A report prepared in 1984 forthe Offshore Operators Committee(OOC) found that thirteen percent (13%)of 319 outer continental shelf (OCS)facilities surveyed at that time usedflotation systems for treatment ofproduced water. Since that same studynoted that nearly all new platforms wereexpected to install gas flotation systemsfor produced water treatment andconsidering that the profile would likelyhave changed in the years:since thatsurvey was conducted, EPA collectedinformation from the MineralsManagement Service and variousindustry sources to update projectionsof existing gas flotation systems. EPAlearned from MMS, which during 1990conducted 1,677 drilling inspectionsand 4,830 production inspections, thatapproximately thirty-five percent (35%)of the offshore facilities in Gulf ofMexico are now using gas flotationsystems for produced water treatment.The distribution of gas flotationsystems, in conjunction with capital andannual cost data compiled for flotationsystems was used to estimate totalcompliance costs.

EPA calculated the BAT annualoperating and maintenance (O&M) costsusing the projections of existing gasflotation systems discussed above. Forthose platforms that already have gasflotation units installed, the annualO&M costs of complying with BATlimitations based on improvedperformance of gas flotation areestimated to be higher than their current

annual O&M costs because ofmodifications and enhancementsneeded to improve system performance.Enhanced removals of oil and grease canbe achieved by existing gas flotationsystems through closer supervision ofthe units by the platform operators,additional monitoring of operatingparameters, proper sizing of the unit toimprove hydraulic loading, additionalmaintenance of the process equipment,and addition and/or proper usage offlocculation enhancement chemicals.These costs are incremental to thecurrent annual O&M costs. EPAestimates that the additional labor andother improvements necessary toachieve compliance with BAT limitswill approximately double the annualO&M costs for existing flotation systemscurrently achieving BPT qualityeffluent.

Existing facilities needing to install agas flotation unit (or other technology)to comply with the limit are projectedto incur costs to design and select atreatment system to meet the BAT oiland grease limit. Total annual O&Mcosts for existing platforms that willneed to install gas flotation weredetermined to be approximately tenpercent (10%) of the capital costs of thenew flotation system. EPA notes that theBAT and NSPS limitations of the finalrule are based on data from existingfacilities identified as beingrepresentative of platforms having well-operated gas flotation units. Thus,although not all existing facilities withgas flotation units would be expected toalready be meeting the BAT and NSPSoil and grease limits of this rule, thedata shows that a portion of the industrycan already comply with the limitationsof this final rule without incurring anadditional cost. Because EPA does notknow how many of these facilitieswould be able to comply withoutincurring additional cost, no allowanceis made in EPA's cost projections toexclude such facilities in determiningthe cost of compliance for this rule.Thus, EPA is confident that compliancecosts are not underestimated andmayeven be overestimated by up to 20-40percent. On balance, however, EPAbelieves these cost projectionsreasonably reflect the aggregatecompliance costs for the entiresubcategory.

The 1984 industry (OOC) report statedthat even in the absence of producedwater limitations more stringent thanBPT, eighty percent (80%) of newdevelopment and production platformswould be designed with gas flotationsystems for treatment of producedwater. Thus, EPA based compliance costprojections on the assumption that in

the absence of NSPS limitations twentypercent (20%) of new platforms wouldnot include a flotation unit in theirtreatment system design. This twentypercent (20%) of new platforms areconsidered to incur an incremental costto comply with NSPS limitations.

In estimating NSPS capital costs, EPAassumed that it was necessary for theoperator to add a flotation system to theproduced water treatment system. Theentire costs for adding on such a systemwere used in.EPA's economic impactanalyses. EPA notes that although somenew platforms would not have plannedto install flotation systems, theplatforms would have contained someother type of treatment technology andit is entirely possible that the alternativesystem would enable compliancewithout incurring additional costs tocomply with the NSPS limitations. EPAalso notes that by adding on a flotationsystem to comply with NSPS limits, theoperator may actually forego installationofother produced water treatment units,with the result being that the gasflotation unit would serve as areplacement system rather than an add-on system, incurring no, or reduced,incremental costs. However, in costingthis rule it has been assumed that anadd-on treatment system will berequired and costs of entire flotationsystems for 20 percent (20%) of all newplatforms have been included.

For those eighty percent (80%) of newplatforms that are expected to includegas flotation in the original design,capital costs consist only of anengineering redesign cost and not a newunit cost. It is assumed that the gasflotation units included in the existingdesign of the new platforms were able,at a minimum, to achieve the currentBPT oil and grease limitations. For thesesystems to achieve the more stringentlimitations of this final rule, EPAassumed that there may be an additionalcost to upgrade the system. A designupgrade could consist of increasing thesystem's retention time throughincreasing the cell size or the additionof another cell, maximizing separationefficiency through properly sizingrotors, gas dispersers, and chemicalinjection equipment, and optimizing thesystem's performance through theaddition of state-of-the-artinstrumentation and controls. Thissystem redesign cost was estimated atfifteen percent (15%) of the NSPSflotation system capital cost.

The NSPS annual O&M costs for newplatforms were calculated using thesame NSPS profile used in thedevelopment of the NSPS capital costs.For the twenty percent (20%) of newplatforms assumed to not already

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include flotation systems in the design,the annual costs are ten percent (10%)of the capital costs. However, for thosenew platforms that already haveflotation systems in the design plans ofthe facility, there are no incrementalannual costs for compliance with theNSPS limitations. EPA assumed thatsince there is a flotation system in thedesign of a facility, there are also annualcosts associated with operation of thatsystem in the financial projection of thatproject. The improved performance ofthat system has been accounted for byimproving the design parameters of theflotation system.

Additional requirements placed onOCS sources under the recentlypromulgated air regulations for OCSsources (57 FR 40792) were alsoconsidered in developing compliancecosts for this rule. Emissions offset costswere calculated for all facilities locatedoff the Southern California coast, sincethis OCS planning area is adjacent to anonshore nonattainment area. Offset costsare assumed to be an annual expenseand are included in the annial O&Mcosts for the produced water treatmentoptions. Offset costs were calculated formtrogen oxide and hydrocarbonemissions were calculated for thisregulation based on annual costs of$15,000 per ton of nitrogen dioxide and$5,000 per ton of hydrocarbons.

e. Onshore Treatment Costs. EPAassumed that those facilities currentlypiping produced water to shore fortreatment would continue to do so andno additional offshore treatment wouldbe necessary. Since they are treating anddischarging produced water whichoriginated in the offshore subcategory,the onshore treatment facilities arerequired to meet the oil and greaselimitations of this final rule and areexpected to achieve compliance througheither upgrading existing equipment orinstalling new treatment equipment. Forthis costing exercise, EPA evaluated thecosts for installing new equipment atthe onshore treatment facilities. For the37 percent of the facilities piping toshore for treatment, EPA developedcosts for onshore treatment by gasflotation, granular filtration, andreinjection technologies.

The onshore treatment costs wereevaluated for both the BAT and NSPSscenarios. However, for the NSPSscenario, EPA projects that the cost toinstall piping to the offshore facilitywould greatly exceed the costs ofinstalling the necessary treatmentcontrol technology onsite at the offshoreplatforms. Thus, EPA predicts that nonew sources will pipe produced waterto shore for treatment. Although EPAwas unable to determine the extent to

which it might happen, it is possiblethat in some instances new sources mayreduce onshore treatment costs bysharing an existing pipeline to shore.

The bis for the onshore treatmentsystem costs are similar to the offshoreper-platform system costs, althoughthere are a few exceptions. Theexceptions are: (1) The offshoreinstallation factor of 3.5 was not used(The multiplier is applied to onshorecosts to account for the increased costof transporting and installing equipmentoffshore. The multiplier is identical tothat value used at proposal and wasderived based on information suppliedby DOE/EIA, equipment vendors,service providers, and other industrycommenters); (2) there were no costs forplatform additions; and (3) no centrifugecost was assigned for the onshorefiltration or reinjection options. EPAassumed that a centrifuge would beunnecessary to dewater the filterbackwash because adequate spacewould be available at an onshoretreatment facility to capture, settle andstore backwash volumes from thegranular filter.3. Membrane Filtration

EPA reexamined the applicability ofmembrane filtration technology for thetreatment of produced water as a resultof additional data obtained on thetechnology and numerous comments onthe March 13, 1991 proposal. In April1991, EPA conducted a samplingprogram of the only full-scale ceramicmembrane filtration unit processing oilfield produced water in the UnitedStates.

EPA's reevaluation of membranefiltration technology concluded thatmembrane filtration technology is stillin the development phase forapplications in the treatment ofproduced water. EPA's samplingprogram clearly indicated that thetechnology is capable of substantiallyreducing the quantities of soluble andinsoluble organics found in producedwater. However, despite the outstandingpollutant removal performance of theceramic membrane filtration unit, theunit experienced operating problemswhich preclude long-term continuoustreatment of the entire produced waterstream to the effluent levels presentedin the proposal. The sampling programbrought to light several operationaldifficulties that, according to theoperator, are experienced with the fullscale unit. The most significant problemexperienced with that unit was foulingof the membrane. The operatoridentified several conditionsresponsible for significant fouling of themembrane surface. These conditions

are: sea water in the produced waterstream from the deck washdown system,high oil and grease loadings on themembrane during upsets, and thepresence of production chemicals in theproduced water. Membrane foulingresults in a significant reduction of fluxacross the membrane and ultimateshutdown of the unit for chemicalcleaning. As a result, the unit wasoperated at twenty percent (20%) of therated design capacity and shutdowns forcleaning were reported to be frequent.An additional adverse effect wasreported to result from recycling of theoil phase of the membrane retenatestream back into the produced watertreatment system. Chemicals added tothe filtration unit which becomeentrained in the oil phase reportedlyresult in decreased separation efficiencyin the upstream separation unit (heater-treater).

EPA also received several commentsregarding the proposal's selection ofmembrane filtration as a preferredtechnology. These comments paralleledEPA's conclusion that membranefiltration is not technically available asa BAT or NSPS treatment option at thistime. The commenters provided dataobtained from the same full scale systemevaluated by the EPA and a pilot scaleunit operating in the Gulf of Mexico.Commenters also provided informationon a polymeric membrane filtrationpilot unit being tested in the North Seaand a literature study which revieweddata furnished by manufacturers and oilcompanies regarding five differentmembrane filtration systems.

4. Produced Water Pollutant LoadingsSimilarly to the March 1991 proposal,

pollutant removals for the differentregulatory options of the final rule weredetermined by comparing the estimatedeffluent levels of pollutants aftertreatment by the BCT/BAT/NSPStreatment system (improvedperformance of gas flotation, filtration,or reinjection) versus the effluent levelsof pollutants associated with a typicalBPT treatment (gas flotation or gravityseparation).In the March 1991 proposal, EPA

characterized BPT treatment using datafrom the 30 Platform Study. Commentsreceived subsequent to the proposalstated that certain pollutants foundpresent in other studies of producedwater effluent had been excluded byEPA and resulted in pollutant removalsbeing underestimated. Severalcommenters also disputed the presenceof one pollutant Included in EPA's BPTcharacterization.

In response to the comments receivedregarding BPT characterization, EPA



developed an expanded date set basedon published studies which includedcharacteristics of produced water. As aresult of this reanalysis, one pollutant,bis(2-ethylhexyl)phthalate, was deletedand anthracene, beazo(a)pyrene,chlorobenzene, di-n-butylpthalate, totalxylenes, cadmium, lead, nickel andradium were added to the list ofpollutants present in produced waterBPT effluent.

Based on the presence of thepollutants in BPT effluent, BAT andNSPS pollutant reductions werereassessed for granular filtration systemsbased on "three facility study" data.Data from gas flotation units determinedto be demonstrating improvedperformance in the 30 Platforir Studywere the primary basis for determiningpollutant reductions from improvedperformance of gas flotation.

C. Produced SandThe methodology used to determine

compliance costs for the zero dischargelimitation for produced sand is based onproduced sand generation rateestimates, onshore disposal costs atpermitted exploration and productionwaste disposal facilities, and onshoredisposal costs at permitted low levelradioactivity disposal facilities. EPAdetermined that no direct marinetransportation costs (from the platformto shore) would be associated with thezero discharge requirement based ondata from the Offshore OperatorsCommittee (COG) produced sand surveyand additional information on producedsand handling and disposal practicessubmitted by the OOC. This informationindicates that produced sand collectedregularly through operation ofdesanders and blowdowns throughvalves on vessels accounts forless thanten percent of the volumes of sandcollectedannually. The majority of sandis collected during scheduled cleanouts.The information also indicates thatninety percent(90%) or nore of theproduced water treatment systemcleanouts produce less than 100 barrelsof produced sand per cloanout. Thecleanouts occur during a platformshutdown and the typical cleanout cycleis once every three to five years.Therefcre, EPA concluded that thevolume of produced sand collected fromvessel blowdowns is small enough thatoperators are able to use the supplyboats that service offshore platforms ona frequent and Tegular basis, rather thancontract for dedicated vessels totransport the waste to shore. Theproduced sand co~lected during tankand vessel ceenoats are typically smallvolumes that cam be transported to shoreusing either the regularly scheduled

supply boats or the work boats charteredto support the sand removal or othergeneral maintenance during theplatform shutdown.

Data evaluated by EPA for this ruleindicates a generation rate of one barrelof produced sand far every 2,000 barrelsof oil produced. EPA calculatedproduced sand volumes using peak yearoil production estimates from theMinerals Management Service. Datafrom the produced sand surveyindicated that, in 1989, thirty-fourpercent (34%) of the produced sandgenerated was hauled to shore fordisposal. The industry does not incurany incremental compliance costs underthis rule for that portion of the producedsand which is already being disposed ofonshore. For determining theincremental costs of the .zero dischargerequirement of this rule, EPAbased itscosts projections on the produced sandvolume being discharged offshore (66percent of all produced sand generated).

In December 1991, the MMS Gulf ofMexico Regional Office issued a Letterto Lessees (LTL) providing guidancelimiting ocean discharges of producedsand contaminated with naturallyoccurring radioactive materials (NORM).This LTL notified operators that, underauthority provided MMS, discharges ofproduced sand with a radiation doserate greater than 25 microroentgen perhour would not be approved. NORM isformed by co-precipitation of solubleradium from the formation water(produced water) along with bariumsulfate, calcium carbonate, and otherscale-producing constituents. Theseprecipitates (as scale) collect in theseparator tank bottoms (solids) alongwith the produced sand. Radionuclidedata included in the produced -sandsurvey indicated that NORM levels forsome of the produced sand volumespreviously discharged to the ocean tin1989) exceed the current MMSguidelines and would now requireonshore disposal. Therefore, EPA notesthat the percentage of produced sandbeing discharged to sea may actually beless than 66 percent of the total volumegenerated. Sinoe the MMS guidelinesare interim guidance and couldconceivably be withdrawn, EPA hascontimud to project compliance costsbased on transporting 66 percent (66%)of produced sand generated annually toshore for disposal. The possiblepresence of NORM in produced sanddid not drive EPA's determination thatzero discharge is appropriate for thiswastestrean, however, because someproduced sand contains NORM. EPAdid consider the presence of NORM forthe purpose of estimating compliancecosts for the zero discharge limitations.

EPA used the data on radioactivitylevels in produced sandto estimateaverage Tadium concentrations for theproduced sand -wastestream. Theradioactivity data submitted provideseither exposure rates expressed inmicroRoentgens per hour (microR/hr) urconcentrations expressed in picocuriesper gram (pCi/g). Average radiumconcentrations end the incrementalincrease in the volume of producedsand hauled to share provided the basisfor estimating radium removals. For theJroducd sand volumes considered toaveelevated NORM levels (25 percent

of produced sand according to OOCdata), EPA assigned costs for disposal atlow level radioactivity disposalfacilities. Produced sand containingNORM above these levels may notactually require disposal at low-levelradioactivity disposal facilities. Toensure compliance costs for zerodischarge were not underestimated,however. EPA considers using thismethodology to be an appropriate basisto project incremental costs of this rule.For the remaining volumes of producedsand (without elevated NORM levels)brought to shore for disposal. EPAassigned costs for disposal at licensedcommercial oilfield waste disposalfacilities.

The pollutant loadings calculationsalso estimated reductions in dischargesof oil and total suspended solids. Theloadings were calculated based on thereductions in produced sand dischargesto the ocean. Oil removals werecalculated using an average oil contentin washed produced sand of 1.63percent based on data submitted inresponse to the proposal.

D. Well Treatment, Completion andWorkover Fluids

This rule requires well treatment,completion and workover fluids to meetoil and grease limitations based on thetechnology of cotreating these fluidswith the produced water treatmentsystem. Based on infornmation providedby industry commenters, the technologyof commingling these fluids withproduced water is available. Treatingthese fluids with prodaced water isconsidered to incur no, or minimal,additional complianoe costs. Costs tooperate properly the produced watertreatment system and monitor forcompliance are accounted for in thecompliance cost projections forproduced water. Some facilities may beunable to treat wall treatment,conm4peton and workover fluids withthe produced water and would incurcompliance,costs under this rule. Thefollowing paragraphs discuss the costingmethodology for those facilities.

12A67



EPA used information submitted byindustry commenters to determine mostmultiple-well facilities are able to treatthe treatment, completion and workoverfluids in the produced water treatmentsystem. Because facilities with fewerthan ten producing wells generate arelatively low volume of producedwater, there is a potential for upset ofthe treatment systems due to inadequateequalization of wastewaters. Forfacilities with fewer than ten well slots,EPA developed compliance costs basedon the technology of capturing andtransporting the wastes to shore fortreatment and/or disposal. Noadditional compliance costs areprojected for the offshore facilities (37percent of existing facilities) that pipetheir produced water to shore fortreatment. Because of the large volumesof produced water treated at theseonshore sites, EPA believes thetreatment, Completion and workoverfluids could be commingled with theproduced water wastestream withoutcausing treatment system upset. Theonshore facility can adequately treat theoccasional slug of treatment fluids andstill maintain compliance with BAT andNSPS limitations.

Based on industry comments, wellworkovers or treatment jobs weredetermined to occur, on average,approximately every four years.According to industry comments andliterature, workover fluids are typicallyreused at least once and treatment fluidscan only be used once. The workoverand treatment fluids volumes andonshore disposal costs estimates areaverages based on the fifteen year periodevaluated for this rule. Average yearlydisposal costs were developed becauseworkover and treatment fluids volumesare not generated, and hence costs arenot incurred, until four years after wellcompletion and subsequently every fouryears thereafter. The well completionfluids volumes and onshore disposalcost estimates are based on a yearlyaverage projection of wells drilled overthe fifteen years followingpromulgation.

The typical discharge volumesassociated with workover, treatment,and completion have been revised sincethe proposal based on industrycomments. The volume of workover andcompletion fluids generated is estimatedto average 300 barrels per well. Thisvolume accounts for a preflush andpostflushing of the well and weightingfluid for a 10,000 foot well. The averagevolume of treatment fluids generated is250 barrels per well.

EPA believes that there will be no costfor the containment of the spent fluidsprior to transporting them to shore for

disposal because during well treatment,workover, or completion, storage tankscurrently exist on the platform or ontending workboats for fluid storage andseparation. (To ensure compliance withthe current BPT limitations prohibitingdischarge of free oil, operators mustmaintain the capability to capture fluidswhich, if discharged, would cause asheen on the receiving waters.) EPAbelieves that these tanks would provideadequate storage for the time betweencapturing the fluids as they come out ofthe well and the time of transporting thefluids to shore.

EPA also did not assign anyincremental costs to the transportationof the fluids to shore. Based oncomments from industry, EPAdetermined that the volumes would besmall and the workboats tending the rig(for treatment, completion, or workoverevaluations) or regularly scheduledsupply boats would have adequatespace to transport the containers ofspent fluids. As discussed in the aboveparagraph, EPA determined that theplatforms would have adequate spaceor storage of the spent fluids for the

periods when the supply boats are notscheduled for the platform or whenoffloading to the supply boats isinfeasible due to weather conditions.

To estimate compliance costs forthose facilities unable to comminglefluids with the produced water, EPAdetermined the most common methodof onshore treatment of spent fluids tobe injection into undergroundformations at a centralized treatmentfacility. The disposal costs are estimatedto be $12 per barrel and are based on thecosts of transporting the fluids from aninland port transfer station to thedisposal facility, solids removal ifnecessary, and injection intounderground formations.

E. Non-Water Quality EnvironmentalImpacts

The evaluation of non-water qualityenvironmental impacts for this final rulegenerally follows the methodologypresented by EPA in the March .1991proposal. This methodology waspatterned after calculations performedby Walk-Haydel and Associates, andsubmitted by the American PetroleumInstitute (API) as part of API's commentsubmission on the 1988 Notice ofAvailability. These impacts werereassessed based on public commentson the March 1991 proposal. Themanner in which those comments wereconsidered and how they affected thenon-water quality environmental impactanalysis are presented in the followingdiscussion.

1. Drilling Fluids and Drill CuttingsSeveral commenters disputed EPA's

estimates of drilling waste volumesrequiring onshore disposal, as well asthe manner in which these wasteswould be transported and the adequacyof available disposal sites. Generally,these comments either: (1) Noted thepotential for improved solids controlequipment to reduce drilling wastevolumes; (2) contended that EPA'sassumption regarding the number ofvessels necessary for transporting thedrilling wastes was an overestimate; (3)contended that EPA had underestimatedthe drilling waste volumes requiringonshore disposal; or (4) stated thatprojected sites for disposal wouldencounter difficulties in obtainingoperating permits. For this final rule,EPA reassessed estimates of theincremental increase in the volume ofdrilling fluids and drill cuttingsrequiring onshore disposal under thevarious options under consideration,reevaluated solids control equipmentpractices and supply boat utilization,updated estimates of the onshoredisposal capacity for oilfield wastes,and reassessed the assumptions andmethodologies used in determiningenergy requirements and air emissions.EPA also took into account the CleanAir Act Amendments of 1990 (andimplementing regulations issuedSeptember 4, 1992 at 57 FR 40792)establishing new limitations onemissions of air pollutants from OCSsources.

2. Produced WaterEnergy requirements and air

emissions associated with the producedwater treatment options were reassessedfor the final rule. At proposal, energyrequirements were calculated based ondetermining the total pressure dropacross a treatment unit, converting thisdifferential pressure value to a powerrequirement (horsepower) needed tooperate the treatment system, thenidentifying fuel consumption. Inreevaluating the non-water qualityenvironmental impacts, EPA noted thatenergy requirements for the granularfiltration option were underestimatedand reinjection option fuel requirementswere overestimated. To estimate moreaccurately the energy requirements forthe final rule, EPA recalculated fuelneeds based on the power requirementsfor each of the various capacities(produced water flowrates) of themodeled treatment systems.

EPA's revised calculations also basedfuel usage calculations on reinjectionpumps driven by natural gas turbinesinstead of electric-driven pumps, which


Federal Registr / Vol. 58, No. 41 / Thursday. March 4. 1993 / Rules and Regulatiits

the calculations for the proposal werebased upon. Gas-driven pumps arepreferred offshore because the platformstypically have gas production on-sitewhich serves as the fuel source.(Electrical reinjection pumps requiremore fuel than gas-driven pumpsbecause of an extra energy conversionstep.)

F. Industry Profile

The location, size, and number ofexisting platforms has been updatedsince the proposal in response tocomments. FirsL information wasgathered to account for current activityin State waters of the offshoresubcategory in the Gulf of Mexico.Second, the Pacific profile was re-evaluated in light of comments. Thenew information is discussed in sectionIII.B.2 of this notice.

Table 3 presents the estimatednumber of existing producing structuresthat are projected to incur costs undertoday's rule. Approximately a percent ofthe existing structures estimated to bearBAT costs lie within the 3-mileboundary.

Table 4 presents the number of newwells projected to be drilled annually bygeographic region and distance fromshore. The estimates includeexploratory, development andproduction wells. Both productive andnon-productive (dry holes) wells areincluded.

Table 5 presents the total number ofnew structures estimated to be installedduring the 15-year period followingpromulgation. Fourteen percent of newstructures are projected for installationwithin 3 miles from shore.

TABLE 3.--EXSTING STRUCTURES INOFFSHORE WATERS

[Estimated to bear BAT costs]

Distane from shore (miles)

0-3 .,3 Total

Guf of MUxico 201 2,516 2,517California .............. 10 22 32Alaska ............ 0 0

Total ............. 211 2.58 2.549

Note: Two existing facilities offshoreAlaska currently reinject produced waterunder state requirements. No compliancecosts have been estimated for-the twoAlaskan facilities since any costs incurredunder this -rule would be minimal.

TABLE 4.--ERAGE AmL NUMBER OFWELLS DRILLED, BAT/BCT AND NSPS

[15 Years following premulation]

Distance from uhom (miles)

0-3 3-4 4-8 >8 Total

Gulf of Mew-ice .... * ....... 60 12 64, 579 715

California . 0 0 29 3 32Alaska ......... (I) (I) (1) (I) 12

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

'Not pmeeflted because Alaska excluded fromzero dischaVe requirement or drllft fluka and drillcuttings.

TABLE 5.-TOTAL PROJECTED NEWFACALITIES

[15 Years following promulgation)

DIstane1rm shor (mlle s)

0-3 3-4 1.4 Total

Gulf of Mexico.. 102 615 755California 0........ 0 0 0Alaska ............ 2 0 2 4

Total ............ 104 38 617 759

VI. Summary of the Most SignificantChanges From the Proposal

This section briefly identifies themost significant changes from theproposal. More detailed discussion ofthese changes, and identification anddiscussion of other issues are includedin other sections of this notice, theDevelopment Document, the EconomicImpact Analysis, and the record for thisrule.

A. Drilling Fluids and Drill Cuttings

1. BCT

In the March 1991 proposal, EPA'spreferred option for BCT control ofdrilling fluids and drill cuttingsrequired zero discharge for wells drilledat a distance of four miles or less fromshore. Discharges from wells drilled ata distance greater than four miles fromshore were proposed to be limited by aprohibition on the discharge of'fiee oil,as determined by the static sheen'test.Wells drilled in the Alaska region wereproposed to be excluded from the zerodischarge limitation, and insteadcomply with the no faee oil limitation.

For this final rule, the delineation fordetermining the zone of zero dischargeis being-set at a distance of three milesfrom shore. Drilling fluids and drillcuttings from wells drilled by existingsources at a distance of 3 miles or lessfrom shore will be prohibited fromdischarge to the surface waters af1theU.S. Discharges of drilliag wastes (fluidsaod cuttings) from wells drilled beyondthis distance will be prohibited fromdischarging free oil. As proposed, wells

drilled off Alaska will.be excluded fromthe zero discharge and will insteadcomply with the no free oil limitation.

2. BAT and NSPSIn the March 1991 proposal, EPA's

preferred option for BAT and NSPScontrol of drilling fluids and drillcuttings was similar to the preferredBCT control and required zero dischargefor wells drilled at a distance of fourmiles or less from shore. Additionalrequirements for control of priority andnonconventional pollutants in drillingfluids and drill cuttings were proposedfor those wells drilled at a distancegreater than four miles from shore andwere as follows: (1) Toxicity limitationset at 30,000 ppm in the suspendedparticulaie phase; (2) a prohibition onthe discharge of detectable amounts ofdiesel oil used either for lubricity orspotting purposes; (3) ho discharge offree oil based an the static sheen test;and (4) limitations for cadmium andmercury in the drilling fluids and drillcuttings at 1 mg/kg each in the wholedrilling fluid at the point of discharge.All wells drilled in the Alaskan regionwere proposed to be excluded from thezero discharge limitation; instead,discharges fom wens off Alaska wereproposed to be controlled by thelimitations on mercury and cadmium,toxicity, and diesel and free oil.

NSPS and BAT limitations of thisfinal rule differ from the proposedlimitations in the following manner.First, as established for BCT, theprohibition on discharges of drillingfluids and drill cuttings is being set ata distance of three miles from shore.Second, for reasons discussed in sectionVII.B.3 of this notice, the term "indetectable amounts" has been deletedfrom the limitation prohibitingdischarges containing diesel oil. Third,instead of the proposed "end-of-pipe"limitation on cadmium and mercurycontent in the whole drilling fluid, EPAis limiting these metals at 3 mg/kg forcadmium and 1 mg/kg for mercury inthe stock barite. Discharges beyond 3miles from-shore, as well as alldischarges of drilling wastes off Alaska,Will be required to comply with thelimitations on mercury and cadmium,toxicity, and diesel and free oil.

B. Produced WatersThe BCT limitation of this final rule

is unchanged from the proposal and isbeirtgesteblisbed equal to current BPTlimits f48 mg/1 menthly avg., 72 mg/ldaily maxj. In Meac 191, EPAproposed establishing oil and greaselimitations for BAT and .NSPS based onmembrane filtration technology (7 mg/Imonthly average, 13 mg/l daily

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maximum) for produced waterdischarges located within four milesfrom shore, and setting BAT and NSPSequal to the current BPT limitations fordischarges beyond that distance.Alternatively, EPA was also consideringsetting the limitations for those facilitieswithin four miles of shore based ongranular filtration technology (16 mg/lmonthly avg., 29 mg/l daily max.). Inthis final rule, EPA is requiring alldischarges of produced water to complywith BAT and NSPS oil and greaselimitations of 42 mg/l daily maximumand 29 mg/1 monthly average based onimproved performance of gas flotationtechnology.

C. Produced SandThe BAT and NSPS limitations for

this wastestream remain unchangedfrom the proposed limitation of zerodischarge. BCT in this final rule willprohibit all discharges of producedsand.

D. Deck DrainageThe BCT limitation of this final rule

is unchanged from the proposal and isequal to the BPT limitation of nodischarge of free oil. In March 1991,EPA proposed establishing oil andgrease limitations for BAT and NSPScontrol of this wastestream based oncommingling deck drainage with theproduced water treatment syste m. Thepreferred option for control of deckdrainage at proposal was to set the BATand NSPS limits equal to thoseproposed for produced water. EPA alsoproposed setting BAT and NSPS equalto BPT (56 FR 10695 and 56 FR 10698).In the final rule, EPA is setting BAT andNSPS limitations equal to the currentBPT limitations prohibiting discharge offree oil.

E. Well Treatment, Completion, andWorkover Fluids

The BCT limitation of this final ruleis unchanged from the proposal and isequal to the existing BPT limitation ofno discharge of free oil. In March 1991,EPA proposed NSPS and BATlimitations prohibiting discharge of welltreatment, completion and workoverfluids which surfaced from the well asa discrete fluid slug, along with a buffervolume preceding and following thatfluid slug. For those treatment,completion and workover fluidssurfacing intermixed, or commingled,with produced water, EPA proposedestablishing oil and grease limitationsfor BAT and NSPS control based ontreatment by the produced watertreatment system. The limitations wereproposed to be equivalent to thoseproposed for produced water.

In this final rule, EPA is deleting thezero discharge requirement for discretefluid slugs. BAT and NSPS limitationsare being set equal to the BAT and NSPSlimitations of this rule for producedwater which is based on improvedperformance of gas flotation (29 mg/lmonthly avg, 42 mg/I daily max).

F. Domestic WasteIn March 1991, EPA proposed

prohibiting discharges of floating solidsand foam. In addition to the limitationsproposed, EPA is incorporatingimitations on discharges of garbage and

plastics, as required by 33 CFR Part 151.Discharges of foam will be prohibitedunder BAT as well as NSPS.

G. Sanitary WasteThe BCT and NSPS limitations for

this wastestream remain unchangedfrom proposal and are equal to existingBPT requirements. BAT is not beingpromulgated for these wastes.

VII. Basis for the Final Regulation-Drilling Fluids and Drill Cuttings

A. BCTSection 304(b)(4)(B) of the CWA

requires EPA to take into account avariety of factors, in addition to the BCTcost test discussed below, inestablishing BCT limitations. Theseadditional factors include "non-waterquality environmental impacts(including energy requirements), andsuch other factors as the Administratordeems appropriate." EPA conducted aninvestigation into both the impacts oftransporting drilling wastes and theavailability of land for drilling wastedisposal (see section VII.A.4). Thesenon-water quality environmentalimpacts and energy requirements andtheir effect on the control of drillingfluids and drill cuttings coveringexisting and new sources are discussedbelow. Also, EPA considered otherfactors such as administrative burdenand enforcement issues in evaluatingBCT options.

1. BCT MethodologyThe methodology for determining

"cost reasonableness" was proposed byEPA on October 29, 1982 (47 FR 49176)and became effective on August 22,1986 (51 FR 24974). These rules setforth a procedure which includes twotests to determine the reasonableness ofcosts incurred to comply with candidateBCT technology options. If all candidateoptions fail any of the tests, or if nocandidate technologies more stringentthan BPT are identified, then BCTeffluent limitations guidelines must beset at a level equal to BPT effluentlimitations. The cost reasonableness

methodology compares the cost ofconventional pollutant removal underthe BCT options considered to be thecost of conventional pollutant removalat publicly owned treatment works(POTWs).

BCT limitations for conventionalpollutants that are more stringent tharBPT limitations are appropriate ininstances where the cost of suchlimitations meet the following criteria:

* The P07W Test: The POTW testcompares the cost per pound of conventionalpollutants removed by industrial dischargersin upgrading from BPT to BCT candidatetechnologies with the cost per pound ofremoving conventional pollutants inupgrading POTWs from secondary treatmentto advanced secondary treatment. Theupgrade cost to industry must be less thanthe POTW benchmark of $0.46 per pound($0.25 per pound in 1976 dollars indexed to1986 dollars).

* The Industry Cost-Effectiveness Test:This test computes the ratio of twoincremental costs. The ratio is also referredto as the industry cost test. The numerator isthe cost per pound of conventional pollutantsremoved in upgrading from BPT to the BCTcandidate technology; the denominator is thecost per pound of conventional pollutantsremoved by BPT relative to no treatment (i.e.,this value compares raw wasteload topollutant load after application of BPT). Theindustry cost test is a measure of thecandidate technology's cost-effectiveness.This ratio is compared to an industry costbenchmark, which is based on POTW costand pollutant removal data. The benchmarkis a ratio of two incremental costs: the costper pound to upgrade a POTW fromsecondary treatment to advanced secondarytreatment divided by the cost per pound toinitially achieve secondary treatment fromraw wasteload. The result of the industry costtest is compared to the industry Tier Ibenchmark of 1.29. If the industry cost testresult for a considered BCT technology is lessthan the benchmark, the candidatetechnology passes the industry cost-effectiveness test. In calculating the industrycost test, any BCT cost per pound less than$0.01 is considered to be the equivalent of deminimis or zero costs. In such an instance,the numerator of the industry cost test andtherefore the entire ratio are taken to be zeroand the result passes the industry cost test.

These two criteria represent the two-part BCT cost reasonableness test. Eachof the regulatory options was analyzedaccording to this cost test to determineif BCT limitations are appropriate.

2. BCT Options Considered

Following a review of the commentsand data received in response to theMarch 1991 proposal, EPA modified thecontrol and treatment options indeveloping the final rule. The followingBCT effluent limitations options fordrilling fluids and drill cuttings wereevaluated for cost-reasonableness by the



POTW and the industry cost-effectiveness tests:

"3 Mile Gulf/California "-All regionsexcept offshore Alaska would be prohibitedfrom discharging drilling fluids and drillcuttings from all wells located within threemiles from shore. All wells located beyondthree miles from shore, as well as all wellsbeing drilled off of Alaska, would bepermitted to discharge drilling fluids anddrill cuttings that are in compliance with theno discharge of free oil limitation asdetermined by the static sheen test.

"8 Mile Gulf/3 Mile California"-Zerodischarge for all wells in the Gulf of Mexicolocated within eight miles from shore andzero discharge for all wells offshoreCalifornia located within three miles fromshore. All wells located beyond eight milesfrom shore in the Gulf of Mexico, beyondthree miles from shore off California, and allwells drilled offshore Alaska would bepermitted to discharge drilling fluids anddrill cuttings that are in compliance with theno discharge of free oil limitation.

"Zero Discharge Gulf/California"-Zerodischarge for all wells located in the Gulf ofMexico and offshore California. All wellsbeing drilled offshore Alaska would bepermitted to discharge drilling fluids anddrill cuttings that are in compliance with theno discharge of free oil limitation.

EPA also evaluated the compliancecosts and non-water qualityenvironmental impacts for dischargeprohibitions at four and six miles fromshore in considering theappropriateness of the three- and eight-mile drilling activity profiles. Theseother options are discussed in detail inthe Development Document for the finalrule. "Miles" as used in this preambleand the regulation in reference to BCT,BAT and NSPS limitations for drillingfluids and drill cuttings refers tonautical miles. Although it is not aconventional pollutant, as is oil andgrease, EPA is limiting free oil as asurrogate for oil and grease under BCTin recognition of its previous use underBPT.

In referring to the options consideredfor control of drilling fluids and drillcuttings, the Gulf of Mexico, Californiaand Alaska regions are used in theoption descriptions and accompanyingdiscussion. Use of the word "Gulf"means any offshore location other thanAlaska and California. EPA uses theterm "Gulf" as a "shorthand" way ofreferring to regulatory options and doesnot exclude other geographic areas fromcoverage under this rule. For the BCT,BAT and NSPS limitations under thisrule, all offshore areas other thanoffshore California and Alaska would berequired to comply with the limitationsestablished for the Gulf of Mexico.

For the purposes of this rule, EPAdetermined that reinjection of drillingwastes into underlying formations at

offshore platforms was not an availabletechnology at this time. Although thistechnology has been demonstrated atsome onshore sites in Alaska and theGulf of Mexico region, the size of theequipment required to perform theseoperations and questions regarding thefeasibility of reinjecting a high solidsslurry into underlying formationsthroughout the offshore regions affectedby this rule currently precludewidespread application offshore.

The removals of TSS and oil andgrease are the only conventionalpollutants selected in calculating theBCT cost reasonableness tests fordrilling wastes. BOD was not usedbecause it was not a parameter normallymeasured in wastewaters from thisindustry since it is associated with theoil content. The use of both BOD and oil(or oil and grease) would essentiallyresult in double-counting pollutantremovals, thus giving erroneous results.(See 47 FR 49181 and 51 FR 24976)

Comments were submitted to EPAregarding specific situations in Alaskanwaters (State and Federal waters off ofAlaska) which make compliance with azero discharge requirement based ontransporting drilling wastes to shore fortreatment and/or disposal difficult.Reasons for this primarily relate to thesevere weather conditions. Because ofsea ice, tugs and barges can only be usedfor 4 months in the summer duringopen-water/broken ice season. Inadditi6n, winter snow and fogconditions severely restrict visibility.White-out conditions occur restrictingair and water travel. Otherconsiderations which hindercompliance with the zero dischargerequirement are the long distances (bothoffshore and onshore) required totransport wastes to areas which may besuitable for land disposal and the lackof permitted land disposal facilities. Forthese reasons, EPA is excluding Alaskanwaters from the zero dischargerequirement. All drilling fluids and drillcuttings discharges from existingsources off Alaska will be required tocomply with the BCT limitationprohibiting the discharge of free oil(measured by the static sheen test), aswell as the BAT limitations on free oil,diesel oil, toxicity, cadmium andmercury. All discharges of drillingfluids and drill cuttings from newsources off Alaska must comply withNSPS limits on free oil, diesel oil,toxicity, cadmium and mercury.

3. BCT Cost Test Calculationsa. Drilling Fluids. Using the volumes

of drilling fluids projected by thecomputer model for each geographicregion, it was estimated that offshore

drilling activity annually generates atotal of 944,364,000 lb/yr ofconventional pollutants (TSS and oil) inthe drilling fluids wastestreem.Applying the BPT restrictions on freeoil, it was estimated that under BPT atotal of 47,807,000 lb/yr of conventionalpollutants are removed from this wastestream for onshore disposal, at a cost of$7,152,000 per year (1986 dollars).Dividing the cost by pollutant removal,the BPT cost per pound of conventionalpollutant removal for drilling fluids is$0.1496 per pound (1986 dollars). Thisvalue is the-denominator of the industrycost-effectiveness test (the second partof the two part BCT cost-reasonablenesstest).

$7,152,000BPT Result ($/lb)=

47,807,000 lbs

.=$0.1496 per pound (1986 dollars)

The POTW test (first part of the twopart BCT cost-reasonableness test) iscalculated by.comparing the cost perpound of conventional pollutantsremoved in upgrading from BPT to theBCT candidate technologies. The "3Mile Gulf/CA" option for BCT, inrelation to BPT requirements on drillingfluids, is projected to remove anadditional 71,292,000 pounds ofconventional pollutants from thedrilling fluids wastestream at anincremental cost of $5,697,000 (1986dollars). These BCT incrementalcompliance costs and pollutantremovals are due to onshore disposal ofdrilling fluids within three miles fromshore (costs and pollutant removalsassociated with the no free oil limitbeyond three miles from shore areattributed to BPT limitations and are notcounted again under BCT). Since thecost reasonableness methodology isconcerned with the cost of conventionalpollutant removal under BCT as it isapplied incrementally to BPT, theeffects of existing NPDES permitlimitations which may be more stringentthan BPT (such as toxicity, diesel andmetals limits for the drilling fluids) arenot considered for the cost-reasonableness tests. These BCT costtests focus exclusively on theincremental costs/removals from rawwasteload to BPT, and the incrementalcosts/removals from BPT to BCT.Dividing the BCT costs by theconventional pollutant removalsprovides a POTW test result of $0.0799per pound.. Since the POTW test resultis less than $0.46 per pound (1988dollars), the result passes the POTWtest.

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$5,697,000POTW Test Result ($/lb)-

71.292.000 lbs

=$0.0799 per pound (1986 dollars)

The industry cost test compares theresult of the POTW test to the coast perpound of the BPT limitations. For the "3

Mile Gulf/CA" option, the test result fordrilling fluids is 0.53.Industry Cost Test=

POTW Test Result 0.0799=- = 0.53

BPT Result ($1lb) 0.1496

Since the test result is less than 1.29,the result passes the industry cost-effectiveness test. Since the BCT

candidate option passes both tests, it isfound to be cost-reasonable.

Additional discussion of thecompliance costs and BCT cost tests areprovided in the DevelopmentDocument. The results of the BCT costreasonableness test for the candidateoptions for drilling fluids are presentedin Table 6. All BCr options consideredfor drilling fluids pass both cost-reasonableness tests.

TABLE 6.-BCT COST TEST RESULTS FOR DRILLING FLUIDS

Conventional Reuatr pOTW costBCT candidate options Pollutants re- comp 1" (198& est

moved'(Mcost Iea"ly yr) 09W6 S)

3 MileGuftRCA..................... 71.3 5.7 0108 0.53Mile GuW3 W e CA ............. .......... ... ........................... 161.6 18.1 0.11 0.75

Zero Disharge Gull and . ............... ................................ ...... 879.1 116.81 0.131 0.89

1 Incremental to BPT.

b. Drill Cuttings. Using the volumes of restrictions on free oil, it was estimated pollutant removal for drill cuttings iscuttings predicted by the computer that, under BPT limitations a total of $0.0677 per pound (1986 dollars). Themodel for each geographic region, it was 9,381,000 lb/yr of conventional results of the BCT cost reasonablenessestimated that the offshore drilling pollutants are removed from this waste test for the candidate options for drillactivity annually generates a total of stream for onshore disposal at a cost of cuttings are presented in Table 7. All846,341,000 lb/yr of conventional $635,000 per year (1986 dollars). BCT options considered for drillpollutants (TSS and oil) in the drill Dividing the cost by pollutant removal, cuttings pass both cost reasonablenesscuttings wastestream. Applying the BPT the BPT cost per pound of conventional tests.

TABLE 7.-BCT COST TEST RESULTS FOR DRILL CUTTINGS

Conventional Reguatory POTW costpollutants re- compliance Ind(s98yBCT cndidate options m° (MM cost( I IaISMycost (MM $1 cost teA

3 Mile GulI/CA . ...... ................... ...... ......................................................................................... 70.5 3.3 0.0 0.698 Mile GuKGJ Mile CA ... .. .......... .. ......... .......... ....................................................................... ................. . ..... 155.2 7.5 0.05 0.72

Zero Dlsc arge Gulf and CA ............................................................................................................................. 825.31 41.0 0.05 0.73

Incremental to BPT.

4. Non-Water Quality EnvironmentalImpacts and Other Factors

The elimination or reduction of oneform of pollution has the potential toaggravate other environmentalproblems. Under sections 304(b) and306 of the CWA, EPA is required toconsider these non-water qualityenvironmental impacts (includingenergy requirements) in developingeffluent limitations guidelines andNSPS. In compliance with theseprovisions, EPA has evaluated the effectof these regulations on air pollution,solid waste generation and management,consumptive water use, and energyconsumption. Because the technologybasis for the limitation on drilling fluidsand drill cuttings requires transportingthe wastes to shore for treatment and/ordisposal, adequate onshore disposalcapacity for this waste is critical inassessing the'options. Safety, impacts ofmarine traffic on coastal waterways, and

implementation considerations such asadministrative burden and enforcementwere other factors also considered. EPAevaluated the non-water qualityenvironmental impacts on a regionalbasis because the different regions eachhave their own unique considerations(e.g., air emissions are a particularconcern in Southern California, whileavailability of disposal sites is morelimiting for the Gulf of Mexico).Although not specifically detailed in thediscussion below, the non-water qualityenvironmental impacts associated withthe projected future drilling andproduction activities in regions otherthan the Gulf of Mexico, California, andAlaska have been consideredacceptable.

The control technology basis forcompliance with the options consideredfor the drilling fluids and drill cuttingswastestreams is a combination ofproduct substitution and/or

transportation of drilling wastes to shorefor treatment and/or disposal. The non-water quality environmental impactsassociated with the treatment andcontrol of these wastes are summarizedin Table 8.

TABLE 8.-NON-WATER QuAL.TY ENVIRON-MENTAL IMPACTS DRILLING FLLmoS ANDDRILL CUTTINGS

Volume ol Air eis- Fuel re-

-Options wat~bfso~nt% 164yr) _ r

3 mile GulfI. CA ........ 690,800 298 34,900

8 "a GuNf/3 mile CA 1,374,300 466 55,700

Zero Dis-chargeGulf andCA ........ ,8t,400 1,798 221,400

Note: Al values presented Incremmtal to currentIndustry practice.



a. Solid Waste Generation andManagement.The regulatory optionsconsidered for this rule will not causethe generation of additional solids as aresult of the treatment technology.However, used drilling fluids and drillcuttings contain high levels of solids,and considerable volumes of thesewastes will be disposed of onshoreinstead of being discharged at thedrilling sites under this final rule.

EPA estimates that drilling activity inthe offshore subcategory generatesapproximately 7.7 million barrels peryear of drilling wastes (drilling fluidsand drill cuttings). Of that volume, it isestimated that about 760,000 barrels peryear of drilling wastes already undergoonshore disposal to comply with currentNPDES permit limitations whichinclude BPT effluent limitations andBAT and BCT limits (based on BestProfessional Judgment). This volume ofdrilling wastes (from the offshoresubcategory) disposed onshore may becompared to EPA's 1987 estimates of361 million barrels per year of drillingwastes generated from the drilling ofwells in the "onshore" and "coastal"subcategories. (See "Report to Congress:Management of Wastes from theExploration, Development, andProduction of Crude Oil, Natural Gas,and Geothermal Energy," U.S. EPA,Office of Solid Waste, EPA/530-SW-88-003, December 1987.) A significantportion of these wastes from onshoredrilling activities are disposed of onsiteand not transported to commercialtreatment and/or disposal facilities.

The drilling wastes generated offshoreand transported to shore for treatmentand/or disposal under this rule wouldbe deposited in commercial landdisposal facilities similar to those usedto manage a portion of the drillingwastes generated by the onshore andcoastal subcategories. These landdisposal sites are generally located nearthe coast where the wastes are brought'to shore. In evaluatingthe impacts fromland disposal of the drilling wastes, EPAdetermined the availability of disposalcapacity on a regional basis. For eachregulatory option, EPA estimated thevolume of wastes requiring landdisposal and the excess, or unused,capacity of disposal facilities.

in the proposal, EPA had estimatedavailable capacity for drilling fluids anddrill cuttings by reviewing permittedcapacity. At that time, data on thedegree to which disposal capacity wasused was not available. For the finalrule, EPA updated capacity estimatesand obtained data on the volumes ofwastes treated at the disposal sites toderive more accurate projections of the"excess" available capacity. The

"excess" available capacity is moreuseful for evaluating the non-waterquality environmental impacts of thevarious options considered for the rule.

While drilling wastes are exemptedfrom federal regulation as hazardouswastes under Subtitle C of the ResourceConservation and Recovery Act (RCRA)(Solid Waste Disposal Act [SWDA], 42U.S.C. 6901-6992(k)), and no Subtitle Dregulations specific to these wastes havebeen developed, there are existing Staterequirements for these wastes. No newfederal requirements for themanagement of exploration andproduction wastes under RCRA SubtitleD have been proposed.

Gulf of Mexico RegionIn developing the proposal, EPA

surveyed state/local regulatory agenciesand disposal facilities in late 1989 andearly 1990 to estimate the available andprojected annual disposal capacities ofsites near the coast which could treatand dispose of drilling wastes. Theresults of this study are documented in"Onshore Disposal Of Offshore DrillingWaste: Capacity and Cost of OnshoreDisposal Facilities," prepared for EPAby ERCE, March 1991..The evaluationreviewed the situation in the threemajor areas where onshore disposal ofoffshore drilling waste would benecessary: Gulf of Mexico, California,and Alaska. Treatment and disposaloptions for offshore waste disposal ineach region were evaluated based ontelephone contacts with knowledgeableindividuals associated with regulatoryagencies or disposal facilities. Estimatesof regional capacity were derived fromtelephone contacts with facilityoperators, recently completed statehazardous waste Capacity AssurancePlans, State data on nonhazardous wastefacilities, and literature sources.

In the Gulf Coast states, oil drillingwastes that are exempt from RCRASubtitle C are generally accorded theregulatory status of nonhazardouswastes but are subject to state disposalrequirements specific to oilfield wastes.Onshore oil drilling facilities areallowed to utilize drilling pits forstorage of drilling fluids and drillcuttings. Upon closure and subject tostate requirements, the drilling wastescan be either buried on-site, landspread, or injected into the underlyingformation. Drilling wastes derived fromonshore drilling operations areoccasionally transported to an off-site,commercial disposal facility for ultimatedisposal. Commercial disposal facilitiesin the region are permitted by the stateto accept specific types of nonhazardousoilfield waste. These facilities are morecommonly used by offshore and coastal

drilling operations and by facilitieslocated in wetlands areas or in inlandwaterways.

In the March 1991 study, disposalsites in the Gulf of Mexico region wereclassified in three categories. First, TierI sites were those permitted to acceptnonhazardous oilfield wastes which arecurrently accepting wastes fromoffshore. These are sites located in closeproximity to drilling sites, generally areaccessible by boat/barge, and chargecompetitive rates for disposal.Operations included in this category arelandfarming, landfilling, and wastetreatment prior to landfilling. Thesecond category, Tier 2 sites, includedfacilities permitted to acceptnonhazardous oilfield wastes but whichwere not accepting wastes from offshoreat that time because of their relative lackof proximity to drill sites, their lack ofmarine unloading terminals or wateraccess, their inability to compete withthe rates charged by Tier 1 facilities, orthe lack of sufficient demand foronshore disposal capacity. Finally, Tier3 sites were those facilities permitted toaccept hazardous waste and whichcould accept nonhazardous oilfieldwaste (at a much higher cost) shouldthere be no other suitable disposalalternatives. The study projected thecombined capacity of Tier I and Tier 2sites at 30.7 million barrels of drillingwastes per year, with Tier 3 sitesproviding an additional 10.9 millionarrels per year of capacity. It was noted

that some portion of the permittedacreage in the Tier I category was notbeing used at the time of the survey;however, the capacity actually used wasnot quantified.

In developing options for the finalrule, EPA improved upon the capacityestimates used for the proposal. EPAbelieves that in addition to the CWA'srequirement to consider non-waterquality environmental impacts, soundenvironmental policy requires that therebe adequate onshore disposal capacityto dispose of drilling fluids and drillcuttings that will need to be barged toshore to comply with the zero dischargerequirements, toxicity limits, and otherrequirements imposed by this rule.Thus, EPA must be careful in projectinghow much landfill capacity is actuallyavailable for this use.

Accordingly, it is appropriate todetermine how much of the permittedcapacity is actually available fordisposal of drilling fluids and drillcuttings generated offshore. Disposalcapacity estimates made by EPA for the1991 proposal did not account forimpacts due to zero discharge limits fordrilling fluids and drill cuttings limitsproposed in a general permit covering

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coastal drilling activities in Texas andLouisiana (55 FR 23348; June 7, 1990).EPA expects to promulgate this generalpermit in early 1993. If promulgated asproposed, EPA anticipates that thispermit will result in an incrementalincrease of 1.1 million barrels per yearof coastal drilling waste requiringonshore disposal as a result of thesenew permit limitations. Although thesewastes are originating in the coastalsubcategory and thus are not affected bythis rulemaking, the coastal drillingwastes do compete for the same onshoredisposal capacity and therefore must beconsidered in determining disposal siteavailability.

EPA reviewed the analysis preparedfor the 1990 and 1991 proposals toevaluate what facilities should beconsidered as available sites for disposalof drilling fluids and drill cuttings fromoffshore oil and gas platforms forpurposes of determining non-waterquality environmental impacts.

- EPA has determined that it should notinclude hazardous waste facilities in itsoverall capacity estimates for this rule.Drilling wastes are exempted fromfederal regulation as hazardous wastesunder subtitle C of RCRA. Whileexempted under subtitle C, there areexisting state requirements for disposalof these wastes. In the Gulf coast states,commercial disposal facilities arepermitted to accept specific types ofnonhazardous oilfield waste. In EPA'sjudgment, adequate disposal capacityfor hazardous waste disposal is anongoing problem, and these hazardouswaste facilities should be reserved foruse to dispose of waste which cannot bedisposed of in any other type of facility.

Because EPA wanted to make arealistic estimate of disposal capacity,EPA included in its estimates ofavailable disposal capacity only thosefacilities that are currently accepting thetype of drilling fluids and drill cuttingsthat would be generated offshore.Facilities excluded from EPA's onshoredisposal capacity estimates include apermitted, but not yet constructed, siteand a facility for which the operatingpermit is currently suspended. EPA alsoexcluded a facility in northernLouisiana because disposal at thisfacility would require at least a five-hour truck ride, resulting in additionalair emissions, energy use, andsignificantly higher disposal costs thanthe other sites which are located closerto shore.

Based on this analysis, total permittedcapacity in the Gulf of Mexico region isestimated at 8.5 million bbl/year. Areview of the wastes receipts from thedisposal facilities indicated thatapproximately 3 million bblof wastes

were accepted for treatment and/ordisposal at these facilities in 1989.Using the permitted capacity estimate of8.5 million bbl/year, approximately 5.5million bbl/year of onshore disposalcapacity is available to accept additionaldrilling wastes (8.5- 3.0=5.5 millionbbl/year available capacity).

Under the regulatory option (ZeroDischarge Gulf/California) requiringzero discharge of all drilling wastes forthe Gulf of Mexico region, EPA projectsan incremental increase of 6.6 millionbarrels per year of drilling fluids anddrill cuttings from the offshoresubcategory requiring onshore disposalat facilities on the Gulf coast.(Accounting for the coastal drillingwastes under the proposed coastalpermit would increase the total by 1.1MMbbl/yr to 7.7 MMbbl/yr.) Comparingthe volume of offshore drilling wastes tocurrent projections of 5.5 million barrelsof available excess disposal capacity inthe Gulf coast region, EPA concludedthat the offshore wastes requiringonshore disposal under this optionwould exceed the available disposalcapacity.

Additional regulatory options withrequirements prohibiting dischargesover lesser geographic areas (optionssetting discharge prohibitions atdistances of 3. 4, 6, or 8 miles fromshore) were evaluated with respect tothe revised land capacity estimates. Forthe options prohibiting discharges ofdrilling wastes within 8 miles of shore,1.4 million barrels per year of wastesfrom the offshore subcategory would bedisposed of onshore in the Gulf region.The combination of offshore wastes (1.4MMbbl/yr) and projected coastal wastes(1.1 MMbbl/yr) represents an estimated45 percent of the projected availableexcess land disposal capacity in theGulf coast region (2.5 MMbbl/yr equals45% of 5.5 MMbbl/yr capacity). For theoptions prohibiting discharges ofdrilling wastes within 3 or 4 miles ofshore, 685,000 bbl/yr or 793,000 bbl/yr,respectively, of drilling wastes from theoffshore subcategory will requireonshore disposal in the Gulf region.Including the 1.1 MMbbl/yr of projectedcoastal-generated drilling wastes, 33 to35 percent, respectively, of the excessland disposal capacity in the Gulf coastregion will be required under the 3 and4 mile options. Additional discussionon the drilling waste volumes requiringonshore disposal and projections ofavailable excess disposal capacity arefurther discussed in sections concerningBCT, BAT and NSPS options selectionfor drilling fluids and drill cuttings.

California RegionCalifornia laws and regulations

provide for oil and gas wastes to bedesignated either hazardous ornonhazardous. Drilling wastes inCalifornia are considered nonhazardousprovided the operator uses onlyapproved additives and fluids. Althoughoffshore drilling wastoa requiringonshore disposal in California would benonhazardous if the operator uses theapproved additives and fluids in thedrilling operations, disposal optionsappear limited. While in theory it maybe possible to dispose of any oilfieldwaste in local Class III (nonhazardouswaste that will not decompose)landfills, local regulatory agencies haveindicated that they are not inclined toallow such disposal unless the waste isfirst stabilized for use as landfill cover.If not stabilized and disposed in a ClassIII landfill, the alternative disposaloption for offshore drilling waste Isdisposal at a Class I hazardous wastesite. In the 1991 study report, permittedClass M (stabilized, nonhazardouswaste) disposal capacity was estimatedat 3.4 million barrels per year and theClass I (hazardous waste landfills)disposal capacity at 6.5-10.5 millionbarrels per year. It was projected thatthe facilities available to perform thestabilization necessary to allow disposalat Class M landfills were operating at nomore than one-half of the permittedcapacity. As part of the finalrulemaking, EPA reevaluated capacityestimates and now projects the onshoredisposal capacity in the Californiaregion at approximately 19.3 millionbarrels per year (including 15.5 MMbbl/yr for Class III landfills).

Under the option requiring zerodischarge of all drilling wastes for theCalifornia region, EPA projects that233,000 barrels of offshore-generateddrilling fluids and drill cuttings wouldrequire onshore disposal at facilities onthe California coast. Comparing that tothe projected disposal capacity in theCalifornia region, EPA concluded thatthe wastes requiring onshore disposalunder this option would require lessthan two percent (2%) of the disposalcapacity. The distances considered inother drilling fluids and drill cuttingsoptions for this rule require less thanone percent of the disposal capacity inthe California region.

Alaska RegionThe 1991 report identified no

commercially operating disposal sites inAlaska accepting offshore drillingwastes. This lack of commercialdisposal sites would require operators totransport the drilling wastes to another


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location such as Washington, Oregon. orCalifornia for disposal; apply -to theState of Alaska for a permit to operatea commercial disposal facility for theoffshore wastes; apply to the State toallow disposal of drilling wastes whichhave been either thermally treated orchemically stabilized (solidification) incurrently-existing landfills; or inject thedrilling wastes into undergroundformations. Injection of slurried drillingfluids and drill cuttings is currentlypracticed on a limited trial basis on theNorth Slope and has been consideredfor onshore use in other regions such asthe Gulf of Mexico. However, thetechnology of injecting slurried drillcuttings is not sufficiently developed toapply to the offshore subcategory at thistime.

Under all options considered by EPAfor this rule, drilling wastes generatedoff Alaska would be excluded from thezero discharge limitation. (See thediscussion of options considered.)Under the limitations imposed by thisrule, EPA does anticipate a relativelysmall increase in the volume ofoffshore-generated drilling wastesrequiring onshore disposal in thisregion. EPA considers the disposaloptions discussed above, in conjunctionwith privately-owned (industry-owned)onshore disposal sites, to provide amplecapacity for disposal of these wastes.Onshore disposal capacity was a factorin excluding drilling wastes in thisregion from zero discharge; however.the difficulties involved in transportinglarge quantities of these wastes to shore(see section VII.A.2 of this notice), andthe limited amount of storage space on-site at offshore drilling facilities(particularly mobile drilling units), alsoserve as a basis for the exclusion.Although the transportation andonshore disposal considerationsprecluded the zero dischargerequirement for this region, these factorsare not considered to prevent theindustry from capturing andtransporting the relatively smallvolumes of drilling wastes that areanticipated to require onshore disposalin this region. The volumes requiringonshore disposal under this rule would,for the most part, be relatively small,anticipated by the operator (and thuscould be planned for accordingly), andtypically occur toward the end of adrilling program when the potential forcausing a halt to drilling would likely beminimized (since the waste volumes tobe handled would either be small oronsite storage would be available). Suchwaste handling practices and operationswould not be inconsistent with current

practices under the current NPDESpermit limitations.

b. Energy Requiements. Energyrequirements for each of the treatmentoptions considered in this rule werecalculated by identifying those activitiesnecessary to support onshore disposal ofdrilling wastes. Those activitiesrequiring fuel consumption includesupply boats to transport the drillingwastes, crane operation at the drillingsites and marine transfer stations tofacilitate off-loading the wastes, trucksto transport the wastes from the marinetransfer station to the onshore disposalsite, and earth-moving equipment at thedisposal site to facilitate landspreadingand landfill operations. Since manydisposal sites are either located atmarine transfer stations, or wastes maybe transferred at marine transfer stationsfrom supply vessels to barges and thentransported on waterways to thedisposal sites, much of the drillingwaste may not actually require trucktransportation. However, the fuelrequirements and air emissionsattributed to truck usage in EPA'sanalysis are considered to approximatethe energy requirements and airemissions resulting from the alternativeuse of barge traffic.

EPA used the volumes of drillingwaste requiring onshore disposal toestimate the number of supply boat tripsnecessary to haul the waste to shore.Projections made regarding boat useincluded types of boats used for wastetransport, the distance travelled by theboats, allowances for maneuvering.idling and loading operations at the drillsite, and inport activities at the marinetransfer station. EPA estimated fuelrequired to operate the cranes at thedrill site and inport based onprojections of crane usage, EPAdetermined crane usage by consideringthe drilling waste volumes to behandled and estimates of crane handlingcapacity. EPA also used drilling wastevolumes to determine the number oftruck trips required. The number oftruck trips, in conjunction with thedistance travelled between the marinetransfer station and the disposal site.enabled an estimate of fuel usage. Theuse of land-spreading equipment at thedisposal site was based on the drillingwaste volumes and the projectedcapacity of the equipment. Themethodology used to determine fuelconsumption is further discussed in theDevelopment Document. Table 8summarizes the incremental increase inenergy requirements for the drillingfluids and drill cuttings optionsconsidered for this rule.

c. Air Emissions. EPA estimated airemissions resulting from the operation

of boats, cranes, trucks and earth-moving equipment by using emissionfactors relating the production of airpollutants to time of equipmentoperation and amount of fuel consumed.The incremental increase in airemissions associated with the controloptions considered by EPA in this finalrulemaking are presented in Table 8.

In developing regulations to controlair pollution from OCS sources pursuantto the 1990 Clean Air Act Amendments,the EPA Office of Air Quality Planningand Standards estimated the airemissions associated with various stagesof oil/gas resource developmentactivities ("Control Costs AssociatedWith Air Emission Regulations For OCSFacilities," Final Report September 30,1991. Prepared by Mathtech, Inc. forEPA). In this study, EPA estimatedlevels of both controlled anduncontrolled emissions fromexploration, development, andproduction operations. Nitrogen oxides(NOJ emissions from exploratorydrilling activities were estimated at 78tons/operation. For comparison, theincrease in air emissions due to offshoreand onshore activities related to onshoredisposal of drilling wastes is estimatedat approximately 1.5 tons of NO. foreach well subject to the zero dischargelimitations.

d. Interaction with OCS AirRegulations. The regulation of airemissions from outer continental shelf(OCS) sources prior to the passage of theClean Air Act Amendments of 1990(CAAA) was the sole responsibility ofthe Minerals Management Service(MMS), which administered theDepartment of the Interior fi)0I) airquality rules (30 CFR 270.45,46). TheCAAA partitioned the regulation of airemissions from OCS sources betweenMMS, which will continue toadminister the DOI regulations for theWestern and Central Gulf of Mexicoplanning areas (off the states of Texas,Louisiana, Mississippi and Alabama),and EPA, which will have responsibilityfor the regulation of OCS sources alongthe Pacific, Arctic and Atlantic coastsand along the Gulf coast off the state ofFlorida.

On September 4,1992, EPApromulgated new requirements tocontrol air pollution from OCS sources(57 FR 40792). The purpose of therequirements is to attain and maintainFederal and State ambient air qualitystandards, and to provide forequitybetween onshore facilities and OCSfacilities located within 25 miles of stateseaward boundaries (i.e., within 25miles of the outer boundary of territorialseas). It should be noted that theeffluent guidelines and NSPS

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promulgated today by this rule underthe CWA apply to all activities locatedseaward of the inner boundary of theterritorial seas and thus includes theterritorial seas, the contiguous zone andthe ocean.

The OCS rule establishes two separateregulatory regimes. For OCS sourceswithin 25 miles of states' seawardboundaries, the requirements are thesame as those that would be applicableif the source were located in thecorresponding onshore area (COA). TheNational Ambient Air Quality Standard(NAAQS) attainment classification ofthe onshore area determines the degreeof additional control and air emissionoffset requirements for OCS sourceswithin 25 miles of a State seawardboundary (except in the Central andWestern GOM planning areas). If anypart of the onshore area adjacent to anOCS planning area is designated asnonattainment for a pollutant, then theregulatory requirements applicable tothe nonattainment classification for thatarea would apply to the entire area ofthe OCS planning area within 25 milesof the State seaward boundary.

Sources located beyond 25 miles ofthe states' seaward boundaries aresubject to federal requirements forPrevention of Significant Deterioration(PSD), New Source PerformanceStandards (NSPS) and, to the extent thatthey are rationally related to theattainment and maintenance of federalor state ambient air quality standards orto PSD, National Emission Standards forHazardous Air Pollutants (NESHAPS).All OCS sources operating adjacent toany State other than Texas, Louisiana,Mississippi, or Alabama will be subjectto requirements under one of the aboveregimes.

In reevaluating the non-water qualityenvironmental impacts associated withonshore disposal requirements for thisrule, EPA considered the effect of theOCS air regulations and staterequirements on the air emissionsresulting from transporting drillingwastes. Areas requiring emissionsoffsets under the OCS air regulations(those adjacent to nonattainment areas)are located seaward of the outerboundary of the territorial seas (states'seaward boundary) to a distance of 25miles from that boundary. Drillingactivity within state waters would notcome under the OCS air regulation, andthose activities beyond the 25 miledelineation would not be subject to thelimitations of a corresponding onshorearea. Emissions in state waters would,however, be subject to state and localrules and may also require offsetting. Inanalyzing the impacts associated withthis rule, EPA quantified potentially

needed emission offsets and calculatedtheir associated costs.

e. Consumptive Water Use. Since littleor no additional water is required abovethat of usual consumption, noconsumptive water loss is expected as aresult of this final rule.

f. Other Factors. Impact of MarineTraffic on Coastal Waterways. Inevaluating the impact of this rule on thepotential for increased service vesseltraffic, dredging, and the widening ofnavigation channels, EPA reviewedMMS data and industry commentsregarding current practice in supplyboat usage. The service vessel usage atoffshore facilities may be as high as twosupply boats per day and two crewboats per day during the explorationand development phases. In general,service vessels make three trips perweek to exploration and developmentoperations and one trip per week toproduction platforms. A boat may visitonly one site or, if it is only going toproduction platforms, may visit as manyas five platforms in a single trip.

The oil and gas industry in the Gulfof Mexico uses the extensive waterwaysystem located within the Gulf coastalstates to provide access betweenonshore support operations and offshoreplatforms and rigs. Oil industry supportvessels moving along coastal navigationchannels include crewboats, supplyboats, barge systems, derrick vessels,geophysical-survey boats, and floatingproduction platforms. Navigationchannels serve as routes for servicevessels traveling back and forth fromservice and supply bases. Generally, oiland gas industry use accounts for lessthan ten percent (10%) of allcommercial usage of the Gulf coastalnavigation channels according to MMSdata.

The most recent data obtained fromMMS show that about 25,000 servicevessel trips are made annually tosupport oil and gas related activities inFederal waters of the Gulf of Mexico.The MMS data does not include vesseltraffic destined for coastal or offshoreactivities in the State territorial seas andtherefore undercounts actual boattraffic. (Note that, in the Gulf of Mexico,about 8 percent of existing platformsand 14 percent of projected new drillingactivity in the offshore subcategory iswithin state territorial seas.) Inestimating the vessel traffic resultingfrom this rule, EPA projected thattransporting drilling wastes ashore froma well subject to zero discharge wouldrequire, on average, 5 to 6 service vesseltrips and result in an incrementalincrease of approximately 740 servicevessel trips per year. Ninety percent(90%), or 670, of these boat trips would

take place in the Gulf of Mexico. Despitethe limitations of the MMS data, it doesindicate that the incremental increase inboat traffic due to this rule would beless than three percent (3%) of allservice vessel traffic.

In evaluating impacts of vessel trafficfor its Environmental Impact Statementfor its five-year comprehensive program,MMS projected that an additional100,000 service vessel trips will resultfrom planned leasing and developmentactivities. Although this boat activitywill occur over the life of the newactivities, the majority of the vesseltraffic is expected to occur within thenext 10-15 years. Upon analysis ofcurrent and projected vessel traffic anddata on navigational channel usage,MMS concluded that some maintenancedredging or deepening of navigationchannels may be required, but no newnavigation channels were anticipateddue to the increased traffic.

Since service vessels must haveunimpeded access to supply bases tocontinue servicing offshore activities,maintenance dredging of navigationchannels will be required regardless ofwhether this rule is promulgated. Thechannels used by vessel traffic intransporting drilling wastes to onshoredisposal sites will also continue to bemaintained since over 700,000 barrels ofoffshore-generated drilling wastes arealready being transported to shore incompliance with NPDES permitlimitations. Recalling that oil and gasrelated traffic accounts for less than tenpercent of all commercial use of thenavigation channels and that oil/gasrelated vessel traffic resulting from thisrule will increase by less than threepercent (3%), any increase in vesseltraffic due to this rule would be smallin relation to the total commercial boattraffic in these channels (3% of 10%equals 0.03%). No significant increasein dredging activities is anticipated as aresult of this rule.

Safety

The industry has argued that injuriesand fatalities would increase as a resultof hauling additional volumes ofdrilling wastes to shore. EPAacknowledges that safety concernsalways exist at oil and gas facilities,regardless of whether pollution controlis required. EPA believes that theappropriate response to these concernsis adequate worker safety training andprocedures as is practiced as part of thenormal and proper operation of offshoreoil and gas facilities.


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Administrative/EncrcementConsiderations

Administrative burden andenforcement issues associated with thisrult were considered nd are discussedin the following section on optionsselection.

5. BCT Option Selection

EPA has selected the "3 Mile Gulf/California" option for BC' effluentlimitations for drilling fluids and drillcuttings. Drilling fluids and drillcuttings from wells drilled by existingsources at a distance of 3 miles or lessfrom shore will be prohibited fromdischarge. Wells drilled by existingsources at a distance greater than 3miles from shore would be allowed todischarge drilling fluids and drillcuttings after meeting the limitation forno discharge of free oil as determined bythe static sheen test. However, for BCTin the Alaska region the BCT limitationfor all wells is being set at no dischargeof free oil as determined by the staticsheen test. The exclusion from zerodischarge only applies to drillingoperations offAlaska; all other offshoreregions, including those in which nodrilling activity is currently takingplace, must comply with the prohibitionon discharges of drilling fluids and drillcuttings within 3 miles from shore.

As discussed above in section VILA.2under each option considered Alaskawas excluded from the zero dischargerequirement because specific situationsexist in Alaskan waters (State and OCSwaters off of Alaska) which makemarine transport and onshore disposalof offshore-generated drilling wastesdifficult. Reasons for this primarilyrelate to the severe weather conditions.Because of sea ice. tugs and barges canonly be used for a short period of timein the summer during open water]broken ice season. In addition, wintersnow and fog conditions restrictvisibility. White-out conditions occurrestricting air and water travel. EPA alsoconsidered the long distances (bothoffshore and onshore) required totransport the wastes to areas which maybe suitable for land disposal, and thelack of current land disposal sites. Forthese reasons EPA is excluding wellsdrilled off Alaska from the zerodischarge requirement. However, thedischarges of drilling fluids and drillcuttings from all wells drilled in theoffshore subcategory off of Alaska willbe required to comply with theprohibition on discharges containingfree oil.

The "3 Mile Gulf/California" option,when compared to the other optionsconsidered for the control of drilling

fluids and drill cuttings, will result inprogress toward the goal of the CleanWater Act to eliminate the discharge ofall pollutants while providing theappropriate balance of theconsiderations required under the Act.As discussed in the above section onBCT costs, this option passes both BCTcost reasonableness tests and iseconomically achievable. EPA believesthe non-water quality environmentalimpacts associated with the "3 MileGulCalifornia" BCr limitations, inconjunction with those additionalimpacts associated with the BAT andNSPS limitations on discharges ofdrilling fluids and drill cuttings and theimpacts due to the coastal drillinggeneral permit for Texas and Louisiana.are reasonable. The non-water qualityenvironmental impacts are discussed inmore detail in section VII.A.4 of thisNotice and the Development Document,EPA rejected a 4-mile zero dischargedelineation due to the small differencein the number of new wells to be drilledbetween 3 and 4 miles, and commentsidentifying this mileage as causing someconfusion and burden on permitting andinspection authorities and operators aswell as a desire expressed by states andfederal regulators to make the zerodischarge zone consistent with the 3-mile delineation for state waters underthe CWA. EPA has also rejected the "8Mile Gulf/3 Mile California" and "ZeroDischarge Gulf/California" options inlarge part due to non-water qualityenvironmental impacts as discussedbelow. Since proposal, EPA hasreevaluated the non-water qualityenvironmental impacts and hasdetermined that several factors havechanged: the amount of waste to bedisposed onshore under this rule, theamount of waste projected to bedisposed onshore under the coastaldrilling permit, and the disposalcapacity for disposing of drilling fluidsand drill cuttings. In reassessing thepollutant removals and non-waterquality environmental impacts for thisfinal rule, EPA revised downward theprojections of energy requirements, airemissions, solid waste (drilling waste)requiring onshore disposal, andavailable "excess capacity" at permittedfacilities available for disposal ofdrilling fluids and drill cuttings.

Prohbition on the discharge (zerodischarge) of drilling fluids and drillcuttings as a treatment and controlmethod (except for Alaska) wasidentified in the March 1991 proposal astechnologically available and costreasonable (passed BCT cost test). EPArejected that option requiring zerodischarge of all drilling wastes at thetime of proposal because of concerns

related to aseociatei non-water qualityenvironmental impacts. In this finalrule, EPA rejets the "Zo DischargeGuilfCalifornia" option because theincremental increase in drilling wastes(6.6 M)dbbl/yr of drilling fluids anddrill cuttings) requiring onshoredisposal exceeds the onshore disposalcapacity in the Gulf coast region and airemissions (54 tons/year) in theCalifornia region would beunacceptable.

As discussed above, under all optionsexcept "Zero Discharge Gulf/California." zero discharge off the coastof California was limited to a distanceof three miles from shore. The SouthernCalifornia air basin currently is innonattainment of National Ambient AirQuality Standards (NAAQS) and thelevel of air emissions associated withsome options considered for thisrulemaking is significant. This regionhas undergone strict controls on airemissions for a number of years in anattempt to improve air quality. Althoughthe absolute quantity of emissionsanticipated off California due tocompliance with today's rule aresubstantially less than those projectedfor the Gulf of Mexico, the California airbasin is one in which impacts on airquality are of particular concern. Airquality in the Gulf region is generallymuch better than in California and.since controls on air emissions in theGulf region are generally less stringentthan in California. there are manyoptions available in the Gulf region ifneeded to offset increased air emissions.In California, however, air qualitycontrols have reached a point whore itis much more difficult to obtainnecessary offsetting reductions In airemissions. In evaluating the airemissions in this rulemaking, EPAdetermined that establishing a zerodischarge limitation at 6 or 8 miles fromshore, or for all wells off of Californiawould result in an unacceptable level(42 to 54 tons/year) of air emissions. Insetting the zero discharge requirement ata distance of 3 miles from shore, airemissions are significantly reduced toan acceptable level (3.3 tons/year). Withregard to the drilling waste volumes forthe California region, EPA identified noonshore disposa capacity problem anddetermined that sufficient disposalcapacity exists for the volume of drillingwaste anticipated under an regulatoryoption, including zero disc fromall wells. Energy requirements (440 bblof diesel fuel per year) in this regionwere also determined to be acceptableunder all regulatory option.

EPA rejects the '8 Mile Gulf/3 MileCalifornia" option also because ofunacceptable non-water quality

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environmental impacts. The amount ofdrilling fluids and drill cuttings thatwould be required to be disposed ofonshore under this rule and the generalpermit for coastal drilling in the Gulf ofMexico would consume approximately45 percent of the excess disposalcapacity in the Gulf coast region. EPAbelieves that selecting this option doesnot leave an adequate capacity marginto dispose of wastes from currentoffshore activities in which drillingwastes fail the static sheen, toxicity ormetals limits (or from the zero dischargezone) and future offshore, coastal, oronshore drilling activities notanticipated by EPA, or other reductionsin capacity caused by cessation ofoperation (voluntarily or throughrevocation of existing permits) ofcurrently permitted sites. EPA's selectedoption of setting the zero dischargerequirement at a distance of 3 milesfrom shore reduces the onshore disposalvolume to an acceptable level.

EPA received a number of commentsrecommending the establishment of thezero discharge zone at 3 miles fromshore. At proposal, EPA considered the3 mile distance in addition to thedistances discussed above. However,EPA declined to choose that distance inits preferred option because industryprofile information on existingplatforms within 3 miles from shore waslimited and projections for new welldrilling activity within 3 miles neededadditional confirmation. In the 1991proposal, EPA solicited informationregarding activity within State waters (3miles), and stated that it would considersetting the final rule on distances otherthan 4 miles, including a 3-miledelineation, if additional informationregarding activity in State watersbecame available. Subsequent to theproposal, EPA received additional dataon the number and location of existingplatforms which increased estimates ofexisting platforms and confirmed earlierestimates of projected activity within 3miles of shore.

EPA also received commentsregarding the potential for confusionand the administrative burden inselecting a delineation other than thepre-existing 3-mile boundary betweenState territorial seas and Federal waters.In all offshore areas with the exceptionof Texas and the Gulf coast of Florida,States assert jurisdiction over themineral rights off their shores up to adistance of three miles. There isoverlapping jurisdiction under the CWAand the Submerged Lands Act (SLA) (43U.S.C. 1301, et seq.). Under the CWA,States have jurisdiction over watersextending three miles from shore.Persons discharging to these waters are

required to comply with any state waterquality standards. Under the SLA, Texasand Florida exercise mineral rights inthe Gulf of Mexico up to 3 marineleagues (approximately 10.35 miles). Inwaters beyond 3 miles, or 3 marineleagues for Texas and Florida, theMinerals Management Service (MMS) ofthe Department of the Interior leasesmineral rights and manages OCSmineral operations under the authorityof the Outer Continental Shelf LandsAct (OCSLA). MMS conducts periodicinspections of offshore oil and gasactivities in the Federal waters underthe OCSLA and, under a Memorandumof Understanding (MOU) with EPA,conducts NPDES complianceinspections on behalf of EPA in thoseareas. Commenters asserted that itwould be more appropriate to select theState/Federal water boundary as thedelineation for a zero dischargelimitation, rather than the 4-mile limitso that MMS or the Region would nothave to inspect for zero discharge at anyfacilities within the one-mile bandbetween 3 and 4 miles while inspectingfor compliance with a different set ofdischarge limitations beyond 4 miles.EPA also believes that the three mileoption, which is consistent with statewaters under the CWA, will help tosimplify the regulatory frameworkapplicable to offshore waters. Anotherfactor considered by EPA is that onlyabout 12 wells per year (less than twopercent of the total wells drilledannually) are expected to be drilled inthe one-mile band between three andfour miles from shore.

EPA agrees that these administrativeand enforcement concerns are valid andhas agreed to adopt the 3-mile option inthe interest of simplifying the regulatoryframework applicable to offshore oil andgas activities.B. BAT and NSPS

1. BAT and NSPS Options ConsideredFollowing a review of the comments

and data received in response to theproposal. EPA modified the control andtreatment options in developing thefinal rule. Three options wereconsidered for BAT and NSPS controland treatment of drilling fluids and drillcuttings for the final rule. These optionsset BAT and NSPS limitations identicalto BCT limits with respect to areas ofzero discharge for drilling fluids anddrill cuttings. BAT and NSPS limitsdiffer from BCT in that they placeadditional limitations on the dischargeof toxic and non-conventionalpollutants for areas (greater distancesfrom shore) in which discharges arepermissible. NSPS is also limiting the

discharge of conventional pollutants.These limitations are being placed onthe drill cuttings as well as the drillingfluids because the data show thatdrilling fluid adheres to drill cuttingsand is discharged along with the drillcuttings. The same pollutants found indrilling fluids are thus found on thedrill cuttings.

The BAT and NSPS limitations onpermissible discharges of drilling fluidsand drill cuttings (e.g., those facilitiesnot covered by the zero dischargelimitations) consist of four basicrequirements: (1) A toxicity limitationset at 30,000 ppm in the suspendedparticulate phase; (2) a prohibition onthe discharge of diesel oil; (3) nodischarge of free oil based on the staticsheen test; and (4) limitations forcadmium and mercury set in the stockbarite at 3 mg/kg and 1 mg/kg,respectively.

The 30,000 ppm toxicity limitation,prohibition on discharges of diesel oiland free oil, and the limitations onmercury and cadmium in the stockbarite are required by general NPDESpermits in Region 6 and 10 (Region 10'spre-approval method for toxicity isbased on the 30,000 ppm limit). InRegion 6, compliance with the nodischarge of free oil limitation isallowed by either the visual or staticsheen test. Permits in Regions 4 and 9also include limits similar to the BATand NSPS limits of this rule. To theextent that the limitations of this ruleare already required by permits, EPAbelieves that this demonstrates that thelimits are technologically available andeconomically achievable. Theavailability and economic achievabilityof the limitations included in this ruleare further discussed in other sections ofthis preamble, the DevelopmentDocument and the Economic ImpactAnalysis (EIA).

The 30,000 ppm toxicity limitation istechnologically available andeconomically achievable and reflects theBAT and NSPS levels of control, asdiscussed in sections XIV and XVI ofthe preamble, the DevelopmentDocument and the EIA. The limitationis the same as that proposed. Thepurpose of the toxicity limitation is toencourage the use of water-based orother low toxicity drilling fluids and theuse of low-toxicity drilling fluidadditives.

EPA believes that the 30,000 ppmtoxicity limit on drilling fluids and drillcuttings is an appropriate BAT/NSPSlimit based on product substitution and/or transporting drilling wastes to shorefor disposal. For the rationale as to whyEPA selected this limitation see sectionXVI. EPA has evaluated product


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substitution and barging/onshoredisposal and finds these technologies tobe available and economicallyachievable for this industry, resulting inno barrier to future entry. Productsubstitution refers to the substitution oflower toxicity drilling fluids andadditives in place of higher toxicityfluids and additives. Productsubstitution as required in the Region 10general permits for oil and gas facilitiesoffshore Alaska and in the Region 6general permit for oil and gas activitiesin the Gulf of Mexico has been upheldby two Federal Circuit Courts. See APIv. EPA, 858 F.2d 261 (5th Cir. 1988)revised opinion, 864 F.2d 1156 (5th Cir.1988) (Reg. 10 permit); NRDCv. EPA,863 F.2d 1420 (9th Cir. 1988) (Reg. 6permit). These standards are notexpected to have any significant non-water quality environmental impactsmainly because the toxicity limits arealready applied by existing permits andoperators utilize product substitutionwherever possible to prevent the needfor onshore disposal. Where the toxicityof the spent drilling fluids and cuttingsexceeds.the toxicity limitation, themethod of compliance with thislimitation would be to transport thespent fluid system to shore for eitherreconditioning/reuse or land disposal.Further discussion on the

* implementation of the toxicitylimitation is presented in section XX.

The prohibitions on the discharge offree oil and diesel oil are intended tolimit the oil content in drilling fluidsand drill cuttings wastestreams andthereby control the priority as well asconventional and nonconventionalpollutants present in those oils. Thepollutants free oil and diesel oil areeach considered to be "indicators" ofthe toxic and nonconventionalpollutants in the complex hydrocarbonmixtures present in those oils. Anindicator pollutant is one that, by itsregulation, will provide control ondischarges of one or more toxicpollutants. Diesel oil is being regulatedas a nonconventional pollutant and anindicator because it contains such toxicorganic pollutants as benzene, toluene,ethylbenzene, naphthalene andphenanthrene. Free oil is beingregulated as a nonconventionalpollutant and an indicator of the toxicand nonconventional pollutants foundpresent in crude and other oils, and(under NSPS) as a surrogate for oil andgrease in recognition of its previous useunder BPT. The sampling and analysisdata demonstrate that when the amountof oil is reduced in drilling fluids, theconcentrations of priority andnonconventional pollutants present in

the fluid (and that portion of drillingfluid which adheres to drill cuttings) arereduced. EPA has determined that thecontrols on diesel oil and free oil willprovide BAT and NSPS-level control ofthe toxic and nonconventionalpollutants present in drilling fluids anddrill cuttings. This method of toxicregulation is necessary because it is notfeasible to establish specific limitationsupon each of the toxic pollutantspresent in the drilling fluids and drillcuttings.

In the March 1991 proposal, EPAproposed a prohibition on the dischargeof drilling fluids and drill cuttingscontaining diesel oil in detectableamounts. Comments received inresponse to the March 1991 proposalquestioned the need to considerdetectability and expressed concernregarding the potential for confusionover the term "in detectable amounts."EPA agrees that inclusion of the term"in detectable amounts" wassuperfluous. Since the proposedprohibition was an absolute prohibitionon any diesel (whether as a mud systemcomponent or an additive for anypurpose), any drilling fluid system towhich an operator had added diesel oilwould be automatically prohibited fromdischarge, regardless of itsconcentration and whether or not it wasabove the analytical level of detection.In addition, any drill cuttings associatedwith that diesel-contaminated drillingfluid system would also be prohibitedfrom discharge. The term "in detectableamounts" has been deleted In this finalrule since the discharge of all drillingfluids and drill cuttings containingdiesel oil is prohibited.

The discharge of diesel oil, either asa component in an oil-based drillingfluid or as an additive to a water-baseddrilling fluid, would be prohibitedunder the BAT and NSPS limitations ofthis rule. The method of compliancewith this prohibition is to: (1) Usemineral oil instead of diesel oil forlubricating and spotting purposes; or (2)transport to shore for recovery of the oil,reconditioning of the drilling fluid forreuse, and land disposal of the drillcuttings. EPA believes that in most casessubstitution of mineral oil will be themethod of compliance with the dieseloil discharge prohibition. Mineral oil isa less toxic alternative to diesel oil andis available to serve the sameoperational requirements.

The diesel oil prohibition istechnologically available because anoperator may substitute the diesel withmineral oil and water-based drillingfluids. Whenever this is not possible,the operator can transport the drillingfluids and drill cuttings to shore for

treatment and/or disposal. The diesel oilprohibition is not expected to have anysignificant non-water qualityenvironmental impacts and iseconomically achievable as shown insection XIV of the preamble and theEIA. Existing NPDES permits prohibitthe discharge of oil-based drilling fluidsas well as diesel added to a drillingfluid for lubricating purposes or a pillto free a stuck drill pipe.

The prohibition on discharges of freeoil as determined by the static sheen testis technologically available andeconomically achievable and.reflects theBAT and NSPS levels of control. Thestatic sheen test requires the operator tocollect a measured sample volume, mixit with a volume of receiving water ina container, and observe for thepresence of a sheen. This pro-dischargetest is preferable to the post-dischargevisual sheen test because It preventsdischarges of fluids containing free oil,rather than merely observing(after thedischarge) for any noncompliance withthe requirement. Further, the staticsheen test is performed under carefullycontrolled conditions (such as lightingand viewing aspect) and can beperformed at any time, while the visualsheen test (and thus discharges relyingupon the visual sheen test) can only beconducted under conditions in whichthe operator can see the surface of thewater and observe for the presence of asheen. The existing BPT limitationprohibits discharges of free oil fordrilling fluids and drill cuttings.Existing permits in Region 9 and 10require operators to use the static sheentest to determine compliance with theno discharge of free oil limit. In Region6, compliance may be determined byeither the static sheen or visual sheentest. This limitation is not expected toresult in any significant non-waterquality environmental impacts underthis rule.

Mercury, cadmium and other metalspresent in discharges of drilling fluidsand drill cuttings are often also foundpresent as impurities in the barite usedas a weighting agent in drilling fluidsystems. In this rule, EPA is limitingmercury and cadmium in the stockbarite as indicator pollutants to controlthe metals content of the drilling fluidsand drill cuttings discharges.Compliance with this limitation Is basedon product substitution of barite fromsources that either do not contain thesemetals or contain themetals at levelsbelow the limitation.

A number of studies have found thatthe level of metals impurities in bariteis a function of the barite source. Baritedeposits occur primarily as either veinor b edded deposits. The concentrations

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of trace metals, including cadmium,mercury, iron, lead, zinc, mercury.arsenic, tin, titanium, and chromiumvary considerably in mined deposits.The bedded, or "clean barite," depositsare relatively pure deposits with tracemetals typically at very low levels. Vein.or "dirty barite,' deposits are quite,impure and contain elevated levels (10-100 times above those of clean barite) ofthe metals. EPA his evaluated data todetermine whether limiting the levels ofcadmium and mercury in stock baritewould also limit the concentrations ofother metals-as well. The results ofEPA's analysis showed that forcadmium in barite, the metals withpositive correlations (the metals werereduced when cadmium was reduced)include arsenic, sodium, tin. titaniumand zinc. For mercury in barite,, themetals with positive correlationsinclude chromium, lead, molybdenum.sodium, tin, vanadium and zinc. Basedon this data, EPA believes limitingcadmium and mercury in stock barite asindicator pollutants will also limit otherrelated metals in discharges of drillingfluids and drill cuttings. This method ofregulation is necessary because it is notfeasible to establish specific limitationsfor each of the toxic pollutants-presentin this wastestream. Based on data inthe API/USEPA Metals Data Base, theavailability and metals content of cleanbarite sources, the barite volumesrequired to support offshore drillingoperations, and existing NPDES permitrequirements, EPA has determined thatthe BAT and NSPS limitations shouldbe set at 1 mg/kg for mercury and 3 mg/kg for cadmium, on a dry weight basisas measured in the stock barite.

In the 195 proposal, EPA includedproposed limitations of i mg/kg each(maximum) of cadmium and mercury inthe discharge of the whole drilling fluidon a dry weight basis (essentially anend-of-pipe limitation). In the 1988notice and 1.991 proposal, EPApresented several additional alternativelimitations on mercury'and cadmiumfor drilling fluids and drill cuttings. Oneof these alternative limitationspresented, by EPA in the 1901 proposalwas a limitation of 3 mg/kg of cadmiumand I mg/kg of mercury based on stockbarite composition. In, its preferredoption presented in the March 1991proposal, EPA proposed, setting thelimitation en cadmium and mercury at1 mg/kg each in the whole drilling fluid.

Subsequent to the March 1961proposal, EPA received comments andinfbrmation regarding die petentiat forthe'presence of cadmium in the.formation itself to cause noncompliancewith limitations applied-at tbapoitofdischarge. In these comment. many

industry representatives recommendedestablishing limits in the final rule oncadmium and mercury in the stockbarite at 3 mg/kg and I mg/kg,respectively. EPA has analyzed datafrom the American Petroleum Institute'sFifteen Rig.Study. In this study, samplesof drill cuttings, used, drilling fluid, andbarite from a number of drilling siteswere sampled for metals content.Results of EPA's statistical analysisindicate that some cadmium present inthe drilling fluids came from a sourceother than the barite. Therefore, productsubstitution could not ensurecompliance with the end-of-pipelimitation in the whole drilling fluidproposed in March 1991. In this finalrule, EPA has rejected controlalternatives establishing limitations oncadmium and mercury at the point ofdischarge and is instead setting thelimitations in the stock barite.

The limitations on cadmium andmercury in stock barite aretechnologically available andeconomically achievable and reflect theBAT and NSPS levels of control. EPAhas investigated the adequacy ofavailable foreign and domestic suppliesof barite to meet the final mercury andcadmium limits of the rule. Thisinvestigation compared foreign anddomestic supplies, with compositionsadequate to meet the final limits, to theprojected industrial demand. Theconclusion was that there are sufficientsupplies of barite capable of meeting thelimits of this rule to meet the needs ofoffshore drilling operations. As part ofits investigation, EPA also consideredthe potential for the increased demandfor clean barite stocks resulting fromthis rule to cause a rise in the cost ofbarite. The estimated increase inbaritecosts was included in EPA's economicimpact analysis for the rule and- found.to be economically achievable. (See theDevelopment Document, EIA andrulemaking record for a detaileddiscussion of the availability andeconomic achievability of the cadmiumand mercury limitation&) Existinggeneral NPDES permits in Regions 6 and10 limit cadmium and mercury-in thestock barite at 3 mg/kg and I mg/kg.respectively. Existing permits in Region9 also limit cadmium and mercury inthe stock barite. Since most existingpermits already limit cadmium andmercury in the stock barite, andcompliance with the limit is assuredprior to the start of dhlling operationsy. obtaining clean. bacite sources, no

significant non-water qnalityenvironmentad impacts associated withthe cadmium and mercury limits areanticipated.

2. Non-Water Quality EnvironmentalImpacts and Other Factors

The non-water quality environmentalimpacts associated with the BAT andNSPS limitations of this rule are thesame as discussed for BCT in sectionVII.A.4.

3. BAT and NSPS Option Seletion

EPA has selected the "3 Mile Gulf/California" option, and rejected theother BAT and NSPS optionsconsidered, for the final effluentlimitations (BAT) and new sourceperformance standards (NSPS). Thisoption is technologically available andeconomically achievable and reflects theBAT and NSPS levels of control. Also,EPA considered non-water qualityenvironmental impacts in selecting thefinal BAT and NSPS options. Theseconsiderations are summarized insection VII.A describing the BCT optionselection. This selected option willprohibit the discharge of drilling fluidsand drill cuttings from new and existingsources at a distance of three miles orless from shore. Now and existingsources at a distance greater than threemiles from shore would be permitted todischarge drilling fluids and drillcuttings after meeting the followingrequirements: (1) A toxicity limitationset at 30,000 ppm in the, suspendedparticulate phase; (2) a prohibition onthe discharge of diesel oil; (3) aprohibition on the discharge of free oilas determined by the static sheen test;and (4) limitations of 3 mg/kg forcadmium and I mg/kg for mercury inthe stock barite. However, for the Alaskaregion, discharges of drilling fluids anddrill cuttings from existing sources willbe excluded from, the zero discharge "limitation. As previously discussed forBCT, discharges in this region aeexcluded from zero discharge because ofthe special climate and safetyconditions that exist for parts of the yearthat make marine transpoertation ofdrilling wastes particularly difficult andhazardous, the-lack ofcurrent onshoredisposal sits and the long distances(offshore and onshore) over which thetransportation, of these wastes wouldhave to occur. Instead, all wells drilledoffshore of Alaska will be required tocomply with the limitations on free oil,diesel oil, toxicity, and metals contentin barite.

VII. Basis for the Final Regulation-Produced Water

A. BCT

1. BCTOptions Considered

EPA evaluated reinjection ofproduced water into underground



formations, granular filtration,membrane filtration, and gas flotation asoptions for the technology basis for thelimitations established in final rule.

EPA rejected membrane filtration as atechnology basis for the rule because ithas not been sufficiently demonstratedas available to support national effluentlimitations at this time. In the proposal,EPA selected membrane filtration as thepreferred technology basis for BAT andNSPS produced water limitations.Membrane filtration is a commerciallydemonstrated technology in otherindustries and several manufacturershave been developing this technologyfor treatment of produced water.Although not yet available to theoffshore oil and gas industry, operatorshave shown interest in membranes andsome offshore testing of full-scalesystems has begun. In the 1991proposal, EPA relied upon pilot scaletest data in proposing oil and greaselimitations. In April 1991, EPAconducted a field study of a membranefiltration unit Installed on an offshoreplatform to obtain additional full-scaledata and performance information.Information collected by EPA during thefield study and comments submitted bythe industry in response to the proposalindicate that the membrane systemtested at full-scale still suffers fromperiodic operational problems (e.g.,clogging, actual treatment capacity lessthan design capacity). EPA continues tobelieve that further development ofmembrane systems (either that systemalready undergoing full scale testing, orother membrane systems underdevelopment) should enable full-scalesystems capable of long-term, effectivetreatment of produced water. However,data currently available does notsupport selection of this technology asa basis for this rule.

Although technologically andeconomically achievable, granularfiltration was rejected as the technologybasis for this final rule. EPA'sevaluation of granular filtrationperformance data indicates that, whilethis technology does provide someremovals of priority andnonconventional pollutants, thepollutant removal efficiency of granularfiltration is generally not as effective asthat attainable through improvedoperation of gas flotation technology. Inaddition, the capital and annualoperation and maintenance costsassociated with granular filtration aresignificantly higher than the costs of gasflotation systems.

The four options selected for finalconsideration in developing BCTlimitations for produced water

discharges were based Other onreinjection or gas flotation technologies.

BPT All Structures: EPA included as anoption setting BCT equal to BPT. By doing so,EPA realized that the removals ofconventional pollutants due to compliancewith stricter standards may not be costreasonable under the BCT cost tests.

Flotation All: All discharges of producedwater, regardless of the water depth ordistance from shore at which they arelocated, would be required to meetlimitations on oil and grease content at 29mg/I monthly average and a daily maximumof 42 mg/l. The technology basis for theselimits is improved operating performance ofgas flotation.

Zero Discharge 3 Miles Gulf and Alaska:Wells located at a distance of 3 miles or lessfrom shore would be prohibited fromdischarging produced water. Facilitieslocated more than 3 miles from shore wouldbe required to meet oil and grease limitationsof 29 mg/I monthly average and 42 mg/I dailymaximum based on the improved operatingperformance of gas flotation technology.Because of the unacceptable level of airemissions associated with reinjection offCalifornia, all wells off California would beexcluded from the zero dischargerequirement. Currently existing single-welldischargers in the Gulf of Mexico would alsobe excluded from the discharge prohibitionbecause the economic impacts of a zerodischarge limit on theseprojects would resultin immediate shutdown and cause significantproduction impacts. As considered for thisrulemaking, single-well dischargers aredefined as single-well facilities whichoperate their own, and do not share,produced water treatment systems.Discharges of produced water from theseexcluded facilities would be required tocomply with the oil and grease limitationsbased on improved operating performance ofgas flotation technology.

Zero Discharge Gulf and Alaska: Thisoption would prohibit all discharges ofproduced water based on reinjection of theproduced water. All facilities off Californiaand all currently existing single-welldischargers in the Gulf of Mexico would beexcluded from zero discharge requirement.They would, however, be required to complywith the oil and'grease limitations developedbased on improved operating performance ofgas flotation technology.

In referring to the options consideredfor control of produced waterdischarges, the Gulf of Mexico,California and Alaska regions are usedin the option descriptions andaccompanying discussion. Use of theseregions in this way is only a"shorthand" way of referring toregulatory options and does not excludeother geographic areas from coverageunder this rule. For the BCT, BAT andNSPS limitations under this rule, alloffshore areas other than offshoreCalifornia and Alaska would be requiredto comply with the limitationsestablished for the Gulf of Mexico.

2. BCT Options SelectionThe options considered for BCT

regulation were evaluated according tothe BCT cost reasonableness tests. The -pollutant parameters used in thisanalysis were total suspended solids(TSS) and oil and grease. All options,except the "BPT All Structures" option,fail the BCT cost reasonableness test.The range of results for the POTW test(first part of the BCT costreasonableness test) test is $10.02 to$32.53 per pound of conventionalpollutant removed. A value less than$0.46 per pound is required to pass thePOTW test. Thus, EPA is establishingthe BCT limitation in this final ruleequal to BPT (48 mg/l monthly average;72 mg/1 daily maximum) for producedwater. There are no non-water qualityenvironmental impacts associated withthis BCT limitation. The BCT costreasonableness tests for the producedwater options are discussed in moredetail in the Development Document.

B. BAT and NSPS

1. BAT and NSPS Options ConsideredThe BAT limitations considered for

produced water are similar to thosepreviously discussed for BCT. The onlydifference is that while BCT options areintended to control the conventionalpollutants, BAT options focus on thecontrol of toxic and nonconventionalpollutants. Oil and grease remains theonly regulated pollutant in producedwater. Oil and grease is being limitedunder BAT as an indicator pollutantcontrolling the discharge of toxic andnonconventional pollutants. Oil andgrease is being limited under NSPS asboth a conventional pollutant and as anindicator pollutant controlling thedischarge of toxic pollutants.

The options considered for NSPS aresimilar to those considered for BAT,with the only exception being that theexclusion for single-well dischargersfrom the zero discharge limitation is notapplicable under NSPS. The single-wellexclusion for BAT was developedbecause the costs associated withrequiring existing single-welldischargers to retrofit filtration andreinjection equipment are sufficientlyhigh that a zero discharge limitation isnot economically achievable andImmediate shutdown of these facilitieswill result in unacceptable productionimpacts, as discussed further in sectionVII.B.3, below. Since new sources areable to allow for adequate space indesigning new facilities and compliancecosts are less for the new sources,economic and production impacts onthese facilities will be less than theimpacts on existing sources.

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2. Non-Water Quality EnvironmentalImpacts

In assessing non-water qualityenvironmental impacts for producedwater, EPA projected energyrequirements and air emissionsassociated with the regulatory optionsconsidered. The following is adescription of the non-water qualityenvironmental impacts and a summaryof the results of the evaluationsidentifying the estimated levels andimpacts for each option.

a. Energy Requirements and AirEmissions. Energy requirements andresulting air emissions for the controloptions considered by EPA arepresented in Table 9. Estimates arepresented incremental to current BPTlimitations and thus represent theexpected increase above currentemissions levels and energyconsumption. On September 4, 1992,EPA promulgated new regulationsestablishing requirements to control airpollution from outer continental shelf(OCS) sources (57 FR 40792). These newrequirements on air emissions apply toall OCS sources located offshore of thestates along the Pacific, Arctic, andAtlantic coasts and along the Gulf coast

off the state of Florida. Those OCSsources located in the Gulf of Mexicowest of 87.5 degrees longitude (i.e., offthe coasts of Texas, Louisiana,Mississippi and Alabama), whore themajority of offshore oil and gas activitiesare located, are not covered by the newrules. Sources of air pollution fromoffshore activities include leaks, oil-water separators, dissolved air flotationunits, painting apparatus, and storagetanks, but more significantly diesel orgas engines for generating electricalpower or driving reinjection pumps"

Energy consumption for the differentoptions was determined based on theprodticed water flowrates and theassociated power requirements of thetreatment systems. For the zerodischarge limitation requiringreinjection of produced water, energyconsumption was based on gas-drivenpumps operating at injection pressuresof 1,800 psL Gas-driven pumps aregenerally preferred by operators for useon offshore platforms because thestructures typically have gas productionon-site which can serve as the fuelsource. When using electric-driveninjection pumps, fuel must beconsumed to generate electricity, thenconverted beck to mechanical energy to

pump the produced water underground,The extra energy conversion stepneeded for eleGtrical reinjection pumpsincreases fuel requirements because ofthe reduced process efficiency.Electrical power is the energy source forgas flotation units, The energyconsumption associated with gasflotation systems was derived based onpower requirements and the fuelnecessary to produce that ievel ofelectrical power.

Air emissfons calculated for producedwater treatment options includenitrogen oxides (NO.), carbon monoxide(CO), sulfur dioxide (SO-) andhydrocarbons (HG). Air emissions weredetermined by applying emissionfactors which estimate air emissionsassociated with the consumption of fuel.The methodologies used to estimate fuelconsumption and-calculate airemissions are described in more detailin the Development Document.

As illustrated in Table 9, the optionrequiring zero discharge of all producedwater greatly increases air emissionsand fuel requirements as compared tothe flotation all option. This is dueprimarily to the energy required tooperate the injection pumps.

TABLE 9.-NON-WATER QuALIY ENVIRONMENTAL IMPACTS PRODUCED'WATER

Fuel re ioennmts (Um~o- TOWa emkion (Wtom

Opion and eF./r)BAT NSPS BAT NSPS

Flotation Ail ............................................................................................................. ................ 157 29 160 31Zero DlsctWrW 3 Mfw Guff AAA al .................................................................. ........................................ 165 152 185 164Zero Dls& arg :Gult & Akeak ............................................................................................ .......................... 977 785 1,041 849

BOE Barrel of oil equivalent.

3. BAT and NSPS Options Selection

EPA hasselected the "Flotation All"option for the final BAT and NSPSlimitations for produced water. Thisoption requires all existing and newsources to meet discharge limitations onoil and grease content (29 mg/l monthlyaverage; 42 mg/l daily maximum) basedon improved performance of gasflotation technology. EPA hasdetermined this option to be availableand economically achievable andreflects the BAT and NSPS levels ofcontrol. Oil and grease is beingregulated under BAT as an indicatorpollutant for toxic and nonconventionalpollutants. Under NSPS, oil and greaseis being regulated both as aconventional pollutant and as anindicator for toxic and nonconventionalpollutants;

Gat flotation is a technology whichhas been used for many years in the

treatment of produced water at offshoreoil and gas platforms and served as thetechnology basis for BPT effluentlimitations. Currently, approximately 35percent of offshorerplatforms use gasflotation in their produced watertreatment systems. At proposal, EPAconsidered establishing limitationsbased on improved operation andmaintenance of gas flotation. technology.At that time, EPA identified problemsassociated with the performanceevaluation that served as the basis forlimitations considered at proposal.Subsequent to the proposal, EPAreceived a number of comments fromindustry claiming that the gas flotationtechnology was indeed capable ofserving as the basis for BAT'andNSPS-limitations and submitted data assupport. These comments and datasupport EPA's contention in theproposal that improved performancewas achievable for gas flotation

treatment systems and the datasubmitted corrected earlier limitationsof the performance evaluation. Thedevelopment of the produced waterlimitations is discussed in more detailin section V.B.1 of the preamble, theDevelopment Document and record forthe rule.

EPA rejected the most stringentoption, zero discharge based onreinjection. Although reinjectiontechnology is feasible in: somecircumstances, some facilities cannotreinject produced water because ofgeologic conditions in specificlocations. Also, the air emissions (1,041tons/year for BAT; 849 tons/year forNSPS) and energy requirements(977,000 BOE/year for BAT; 785,000BOEyear forNSPS) associated with thisoption at offshore facilities-, especiallyin light of the, air emissions and energyrequirementeassociated'with potentialfuture requirements for facilities in the



coastal subcategory (see e.g., proposedproduced water permit proposing zerodischarge of produced water based onreinjection at coastal facilities inLouisiana and Texas, 57 FR 60926(December 22, 1992)), are unacceptablyhigh. EPA also considered that a zerodischarge requirement based onreinjection under BAT would result incapital costs of $3 billion, with a peakannualized cost of $737 million (year 1;1991 dollars). Zero discharge based onreinjection under NSPS would result incapital costs of $2.6 billion, with a peakannualized cost of $391 million (year15; 1991 dollars). In light of thestatutory mandate to consider cost insetting BAT and NSPS, and thepossibility that the industry might berequired to bear the costs of reinjectionin the coastal subcategory, EPAconsidered the very high aggregate coston a nationwide basis in reinjecting thereinjection option. Also, reinjection forall production structures (both new andexisting sources) is projected to result ina 1.0 percent loss in production (121million barrels of oil equivalent (BOE)over the 15-year period analyzed for thisrule. This production loss, especially inlight of the production loss that mayoccur as a result of potential futurerequirements for facilities in the coastalsubcategory, are unacceptably high.This loss of production is not merely acost concern. Loss of production hasindependent significance in light of thestatutory directive that EPA considerenergy impacts in establishing effluentlimitations guidelines and new sourceperformance standards under the CleanWater Act.

Finally, although reinjection is theonly technology identified that wouldcontrol naturally occurring radioactivematerials (NORM) that may be presentin produced water at offshore facilities,EPA believes that it would be prematureto require zero discharge based onreinjection at this time. EPA hasexamined the existing informationconcerning the presence ofradionuclides in the effluent of offshoreoil and gas facilities. The results of thisanalysis are summarized in two supportdocuments entitled "Prevalence ofRadium in the Gulf of Mexico," (EPAJanuary 15, 1993) and "Summary ofProduced Water Radioactivity Studies,"(EPA January 1993).

As is discussed in more detail in thesedocuments, the data concerning thepresence of radionuclides in theoffshore subcategory are limited andexist only for a small number ofplatforms throughout the offshoresubcategory. Most of the data that existare from facilities in the coastalsubcategory; of the offshore data that

exist, most sampling took place atfacilities within three miles of the coastof Louisiana. In addition, the data thatdo exist show wide variability in theconcentration of radionuclides inproduced water. The limited data thatexist are not from studies designed todetermine the distribution ofradionuclides from oil and gas facilitiesacross the offshore subcategory. Inaddition, EPA used the very limiteddata it has (data from a total of sixplatforms out of 2,549 platforms acrossthe entire subcategory, which EPA doesnot believe are necessarilyrepresentative of produced waterdischarges across the entire Gulf ofMexico or the entire offshoresubcategory) to make a preliminaryestimate of risk to human health fromproduced water effluent in the offshoresubcategory. As discussed further in thesupport document referenced above, inaddition to EPA's uncertainty aboutwhether the few platforms from whichdata were collected are representative ofthe entire subcategory, there are severaladditional difficulties inherent in thesepreliminary risk estimates.

EPA recognizes that it does not carrya high burden of demonstratingenvironmental harm from pollutants orof demonstrating environmental benefitsof its technology-based effluentlimitations guidelines and NSPS. EPAalso does not have an obligation tosample each facility within asubcategory to identify pollutants to beregulated. At the same time, however,the CWA gives EPA discretion todetermine when it has sufficientinformation to make a decision toregulate a pollutant.

In the case of this particular rule, EPAhas determined that it does not havesufficient information concerning thepresence of radionuclides in producedwater effluent across the entiresubcategory to regulate radionuclides atthis time. EPA believes that this is aclose case, but given the limited amountof information EPA has characterizingthe presence of radium in entireoffshore subcategory, EPA is exercisingits discretion not to control radium inthis rule. While EPA believes thatregulating radionuclides that may bepresent in produced water is premature,EPA intends to obtain more informationabout the presence of radionuclides inthe offshore subcategory by requiringradium monitoring requirements inNPDES permits for this subcategory.EPA has promulgated suchrequirements in its most recent permitissued for the OCS in the Western Gulfof Mexico. (57 FR 54642; November 19,1992).

EPA also rejected the Zero Discharge3 Mile Gulf and Alaska option becauseEPA has determined that gas flotation isthe appropriate technology basis forBAT and NSPS established by this rule.EPA has no basis in terms of the factorsconsidered in making thisdetermination and in rejecting zerodischarge to require zero discharge foronly a small segment of the facilitieswithin the offshore subcategory.

IX. Basis for the Final Regulation-Produced Sand

A. BCT, BAT and NSPS OptionsConsidered

EPA considered two options for thiswaste stream: (1) Establish therequirement equal to the current NPDESpermit limitations prohibitingdischarges of free oil; or (2) prohibitdischarge of produced sand,technologically based on transporting toshore for treatment and/or disposal. Thetechnology basis for the option limitingfree oil content is a water or solventwash of produced sands prior todischarge. The method of determiningcompliance with the free oil prohibitionwould be the static sheen test. Theprohibition on the discharge of free oil(as an indicator of toxic andnonconventional pollutants) or the zerodischarge requirement for producedsand would reduce or eliminate thedischarge of any toxic pollutants in thefree oil to surface waters.

B. Option SelectionEPA has selected the zero discharge

option for BCT, BAT and NSPS controlof produced sand. The technology basisfor this limitation is transportation toshore for treatment and/or disposal.EPA has determined that zero dischargereflects the BCT, BAT and NSPS levelsof control because, as it is widelypracticed throughout the industry, it isboth economically and technologicallyachievable: The total cost of zerodischarge under the rule is estimated at$4 million (1991 dollars) for the entireoffshore subcategory.

EPA does not consider the prohibitionon -the discharge of free oil indicative ofa "best available" or "bestdemonstrated" technology. Asdiscussed in section VI.C., onshoredisposal is widely practiced throughoutthe industry as a means to comply withcurrent NPDES permit limitations onfree oil discharge. Onshore disposal isusually selected by operators because ofeconomics (costs of on-site washing arecomparable to costs of onshoredisposal), logistic considerations(scheduling or space), or because thesand fails NPDES permit limitations

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even after washing. Data submitted froman industry-sponsored studydemonstrates the variability of oilcontent in washed produced sand. Theoil content of washed produced sand inthe study ranged from 0.66 to 4.2percent by weight. With the exceptionof a smallpercentage of the sand whichis removed periodically from piping lowpoints and tank blowdowns, producedsand discharges are infrequent bulkdischarges occurring during scheduledshutdowns of the produced watertreatment system. Sand washingsystems are generally contracted fromservice companies as needed, althoughsome operators permanently install sandwashing systems on selected platformsto serve as a central facility to receiveand clean wastes from other sites. Datasubmitted by the industry regardingsand washing performancedemonstrates that even in the case of awashing system which provides forremoval of the free oil, residual liquidsand solids (by-products from washing)remain which are unable to meet the nofree oil limitation and they must bedisposed of in a manner other thanocean discharge (typically by onshoretreatment and disposal).

In the March 1991 proposal, EPAsuggested the possibility of requiringzero discharge only for those facilitieswithin 4 miles from shore if informationshowed that the volumes associatedwith a zero discharge limit for allproduced sand were excessive. EPAreevaluated projections of producedsand generation and onshore disposalcapacity in developing this final rule,and has confirmed that zero discharge ofall produced sand is achievable and theappropriate limitation for BCT, BAT andNSPS. Therefore, EPA is rejecting the 4-mile option for produced sand.

EPA did not perform a BCT cost teston the no discharge of free oil option,because no, or minimal, incrementalcosts would be incurred. NPDESpermits currently limit discharges ofproduced sand containing free oil, withcompliance determined by visual sheentest.

The basis for the compliance costsassigned to the zero discharge option ispresented in section V.C. Although BPTlimitations for produced sand havenever been promulgated, existingNPDES permits prohibit the discharge offree oil in the produced sandwastestream. For the purpose ofconducting the BCT cost reasonablenesstest for the rule, the BPT level of controlis considered to be equal to the no freeoil limitation of the existing permits.Thus, BPT costs and pollutant removalsare determined as the costs/removalsassociated with the onshore disposal of

34percent of produced sand generated,and the costs/removals associated withwashing/discharge for 66 percent of theproduced sand generated annually. Thecosts and pollutant removals due toupgrading from BPT to the candidatezero discharge BCT limitation aredetermined by the costs/removalsassociated with onshore disposal of theproduced sand currently discharged atsea (66 percent of the produced sandgenerated annually).

EPA encountered difficulties inestimating the cost of BPT for producedsand. EPA was unable to obtain firmestimates of sand washing costs fromindustry operators. EPA did receivesand washing cost estimates of $125 perbarrel of produced sand from anequipment vendor. Since the estimate ofsand washing is substantially higherthan EPA and industry estimates of thecost for onshore disposal of producedsand, EPA does not consider the $125per barrel quote to be representative ofthe industry-wide cost of BPT. Also, thesand washing estimate provided by thevendor was for a prototype sandwashing system under deyelopment andwas estimated as the cost tor ademonstration washing project.

The cost for sand washing can bedifficult to estimate, even for theoperators. The cost per unit volume ofsand can vary significantly as a functionof the sand volume washed, difficultiesencountered in washing, and thesuccess (or lack of success) in washingthe sand. As discussed in section V.C.,produced sand wastes are infrequentlydischarged (typically removed fromvessels once every three to five years)and can vary widely in volume (usuallyless than 100 barrels per vesselcleanout, although downhole problemscan infrequently result in substantiallygreater volume). Depending on thevolume of sand generated, schedulingconstraints, and other economic andlogistical considerations, operatorschoose between: (1) Sand washing anddischarge on-site; (2) transporting thesand to another platform where the sandfrom several platforms may be washedand discharged; or (3) onshore disposal.If sand washing is selected by theoperator, it is usually contracted out tooffshore service companies. The goal ofthe sand washing is to reduce the oilcontent of the produced sand to theextent that the discharge complies withthe no free oil limitation. There is,however, no guarantee that sandwashing will be successful. If afterwashing the produced sand is stillunable to comply with the no free oillimit, onshore disposal is usuallynecessary (and therefore incurring bothwashing and onshore disposal costs).

Also, according to data submitted by theindustry, the sand washing evolutionproduces wastes (washing liquids and aportion of the solids) which are unableto meet the no free oil limit. Thesewastes are typically disposed ofonshore.

For the purpose of conducting theBCT cost reasonableness test, and basedon the information discussed above andthe frequency at which produced sandis currently disposed of onshore as analternative to sand washing, EPAestimated the cost of sand washing to becomparable to the cost of onshoredisposal. The average industry-wideBPT cost of sand washing is estimatedat $10 per barrel of produced sand.Considering that day rates for offshoreservice vessels are approximately $3,000per day and that produced sandvolumes are typically less than 100barrels each, it would be difficult foroperators to achieve significantly lowersand washing costs even if the producedsand from several platforms arecombined. Using a higher per barrelsand washing cost for BPT (as would besuggested by the equipment vendorestimate discussed above) provides alower value in the BCT industry costtest and would make the BCT zerodischarge limitation more costreasonable.

Based on the volumes of producedsand washed offshore and the volumesdisposed of onshore under currentlimitations, EPA estimates a BPT cost of$2.4 million (1986 dollars) andconventional pollutant removals of 68.8million pounds, resulting in an overallBPT cost per pound of $0.036 per pound(1986 dollars).

The zero discharge limitation, inrelation to the existing no free oil limiton produced sand, is projected toremove an additional 129.2 millionpounds of conventional pollutants at anincremental cost of $2.3 million (1986dollars). The BCT costs and pollutantremovals result in a POTW test result of$0.018 per pound (1986 dollars). Sincethe POTW test result is less than $0.46per pound (1986 dollars), the resultpasses the POTW test.

For the industry cost effectivenesstest, the result of the POTW test isdivided by the BPT cost per pound, andresults in a value of 0.51. Since theresult is less than 1.29, the result passesthe industry cost-effectiveness test.Since the zero discharge limitationpasses both tests, it is found to be costreasonable.

Based on existing data, EPA isunaware of any unacceptable non-waterquality environmental impactsassociated with this produced sandlimitation. Cleanout of produced water



treatment systems typically producesless than 100 barrels of produced sand.The clenouts occur during a platformshutdown and typical cleanout cycle isonce every three to five years. Thevolume of produced sand collected fromvessel blowdowns is small enough thatoperators are able to use the supplyboats that service offshore platforms ona frequent and regular basis, rather thancontract for dedicated vessels totransport the waste to shore. Theproduced sand collected during tankand vessel cleanouts are typically smallvolumes that can be transported to shoreusing either the regularly scheduledsupply boats or the work boats charteredto support the sand removal or othergeneral maintenance during theplatform shutdown.

EPA is aware of current efforts byindustry to develop technologies thatwould wash produced sand moreefficiently than washers currently in useand achieve additional pollutantremovals. In light of this ongoing effort,MMS and DOE have raised the concernthat the imposition of a zero dischargerequirement on produced sand willprevent the development of improvedsand washing technologies. Also, as partof the ongoing environmentalassessment for offshore new sourcepermits to implement these offshoreguidelines, additional information isbeing gathered on the characteristics ofproduced sand, including NORM levelsin that waste stream.

MMS and DOE have indicated that itwill provide EPA with additionalinformation on these issues. EPAwelcomes information from allinterested parties on the feasibility andpollutant removal efficiency of newproduced sand washing technologies,the fate of solvents from produced sandwashing (i.e., treatment, recycle ordisposal), the characteristics ofproduced sand, the availability ofdisposal sites, and appropriate sitespecifications and requirements fordisposal of produced sand that containsNORM, including possible disposalalternatives such as down-hole disposalin abandoned wells. EPA will considerrevising the zero discharge requirementfor produced sand, if appropriate, afterevaluating this information. If atechnology-based limit contained in anNPDES permit is based on the zerodischarge requirement for producedsand in this guideline, and the guidelineis subsequently revised to permitdischarge with limitations based on newsand washing technologies, the anti-backsliding provision of the CWA,section 402(o), would not precluderevision of the zero discharge permitlimit consistent with the revised

guideline (see (40 CFR 122.44 (1)(1) and122.62)).

X. Basis for the Final Regulation--DeckDrainage

A, Options ConsideredBPT limitations for deck drainage

prohibit the discharge of "free oil."Typical BPT technology for compliancewith this limitation is a "skim pile"which facilitates gravity separation ofany floating oil prior to discharge of thedeck drainage. The options consideredby EPA for this rule were: (1) Prohibitthe discharge of free oil; or (2) set thelimitation for deck drainage equal to thelimitation established for producedwater under this rule, technologicallybased on commingling and treating deckdrainage with produced water.

B. Option SelectionEPA has selected the option requiring

no discharge of free oil for BCT, BATand NSPS control of deck drainage; EPAhas determined that these limitationsand standards properly reflect BCT,BAT and NSPS levels of control. EPAdid not identify any other availabletechnology for this waste stream.Because of the difficulties in obtaininga representative sample of this wastestream for conducting the static sheentest since the effluent is located in aninaccessible location, compliance withthis limitation is determined by thevisual sheen test. Deck drainage" istypically collected in a sump tankwhere initial oil/water separation takesplace. Water discharged from the sumptank Is usually directed to a skim pile,where additional oil/water separationoccurs. The separation process in theskim pile typically occurs beneath theocean surface, and the separated wateris discharged to the ocean from thebottom of the skim pile. (The skim pileis essentially a bottomless pipe withinternal baffles to collect the separatedoil.) The difficulties in obtaining arepresentative sample of skim pileeffluent preclude the use of the staticsheen test for this wastestream. (Theoperation of a skim pile is discussed inmore detail in the DevelopmentDocument.)

In the proposal, EPA presented as itspreferred option establishing effluentlimitations for deck drainage based oncommingling the deck drainage with theproduced water. As such, limits basedon filtration within 4 miles from shore,and oil and grease limits equal tocurrent produced water BPT wereselected as preferred in that proposal.Upon review of Information received bythe Agency since proposal, EPAdetermined that because of adverse

effects on the produced water treatmentsystem, basing the limitations oncommingling deck drainage withproduced water is not technologicallyavailable. Commingling deck drainagewith produced water was rejectedbecause: (1) The resulting flowvariations could result in frequentupsets of the produced water treatmentsystem; (2) oxygen-enriched deckdrainage water, when combined withthe high salt content of produced watercould result in increased corrosion; (3)oxygen present in deck drainage maycombine with iron and sulfide inproduced water causing solidsormation and fouling treatment

equipment; and (4) detergents used indeck washdown cause emulsification ofoil and may degrade the produced watertreatment process.

EPA considered and rejected theoption of establishing limitations ondeck drainage based on an add-onsystem specifically designed to treatonly deck drainage. An add-ontreatment specifically designed tocapture and treat deck drainage, otherthan the type of sump/skim pile systemstypically used, on of shore platforms isnot technologically feasible. Deckdrainage discharges are not continuousdischarges and they vary significantly Involume. At times of platformwashdowns, the discharges are ofrelatively low volume and areanticipated. During rainfall events, verylarge volumes of deck drainage may bedischarged in a very short period oftime. A wastewater treatment systeminstalled to treat only deck drainagewould have to have a large treatmentcapacity, be idle at most times, and haverapid startup capability. Since startupFeriods are typically the least efficientor treatment systems and offshore

platforms have limited available spaceor storage of the volumes of deck

drainage which occur, EPA determinedthat an add-on treatment systemappropriate for the treatment of deckdrainage was not available.

Since BCT, BAT and NSPS are beingset equal to the current BPT, there areno costs or non-water qualityenvironmental impacts associated withthis limitation andit is available andeconomically achievable. The BCTlimitation of no discharge of free oil Isalso considered to be cost reasonableunder the BCT cost test. Since thePOTW test result and the industry cost-effectiveness test results are both zero(and therefore pass their respectivetests), the limitation is cost reasonable.This determination that zero BCT costresults in passing the costreasonableness test is consistent withthe BCT methodology which became

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effective August 22, 1986 (51 FR 24974;July 9, 1986).

XI. Basis for the Final Regulation-WellTreatment, Completion, and WorkoverFluids

A. BCT

EPA is establishing BCT prohibitingdischarges of free oil under BCT for thisrule. Compliance with this limitationwould be determined by the static sheentest. Based on the available dataregarding the levels of conventionalpollutants present in well treatment,completion and workover fluids, EPAdid not identify any options whichwould pass the BCT cost test other thanestablishing the limitation equal to thecurrent BPT prohibition on dischargesof free oil. Using the pollutant loadingsdata presented for these fluids in theDevelopment Document and theestimated compliance costs andpollutant removals for the optionestablishing oil and grease effluentlimits on-these fluids, the results fail theBCT cost reasonableness test. There areno costs or non-water qualityenvironmental impacts associated withthis BCT limitation and, since it is equalto BPT, it is available and economicallyachievable. The BCT limitation is alsoconsidered to be cost reasonable underthe BCT cost test. Since the POTW testresult and the industry cost-effectiveness test results are both zero(and therefore pass their respectivetests), the limitation is cost reasonable.

B. BAT and NSPS

1. BAT and NSPS Options Considered

Well treatment, completion, andworkover fluids may either stay in thehole, resurface as a concentrated volume(slug), or surface from the welldispersed with the produced water. Twooptions were considered for BAT andNSPS control for this waste stream: (1)Prohibit the discharge of free oil; or (2)meet the same limitations on oil andgrease content as established under thisrule for produced water.

In the options considered for BAT andNSPS, free oil or oil and grease are beinglimited as an indicator pollutant for thecontrol of toxic and nonconventionalpollutants. Oil and grease would also belimited under NSPS as a conventionalpollutant. Compliance with the free oilprohibition would be determined by thestatic sheen test.

2. BAT and NSPS Option Selection

EPA is establishing BAT effluentlimitations and new source performancestandards (NSPS) for well treatment,completion, and workover fluids equalto the BAT and NSPS requirements for

oil and grease content in producedwater. EPA has determined that theselimitations and standards properlyreflect BAT and NSPS levels of controlfor well treatment, completion andworkover fluids. The technology basisfor this limitation is commingling andtreating the treatment, completion andworkover fluids with the producedwater wastestream. This limitationrequires all existing and new sources tomeet the discharge limitations on oiland grease content of 29 mg/l monthlyaverage; 42 mg/l daily maximum.Although it is a conventional pollutant,oil and grease is being regulated underBAT as an indicator for toxic andnonconventional pollutants. UnderNSPS, oil and grease is being regulatedboth as a conventional pollutant and asan indicator for toxic andnonconventional pollutants. Thosefacilities unable to commingle withoutcausing a treatment system upset couldcomply by transporting the fluids toshore for recycle and reuse, whereappropriate, or disposal.

EPA has determined that BAT andNSPS oil and grease limitations basedon commingling well treatment,completion and workover fluids withproduced water are available andeconomically achievable based oninformation regarding industryoperating practices, commentssubmitted by industry representatives,and an industry report on the treatmentof these fluids (Hudgins, C.M.,"Chemical Treatments and Usage inOffshore Oil and Gas ProductionSystems," October 1989.). Welltreatment, completion and workoverfluids often surface commingled withproduced water, rather than as adiscrete volume (or slug). At timesoperators are unable to predict when thefluids will surface or even distinguishwhen the return has occurred. At suchtimes, the treatment, completion andworkover fluids are commingled in theproduced water treatment system eventhough there is no existing requirementto do so.

Some comments on the proposed rulesubmitted by industry representativesstated that the final rule should requiretreatment, completion and workoverfluids to be treated the same asproduced water based on commingling.Also, an industry-prepared reportsubmitted by API (Hudgins, 1989) statesthat, except for platforms with very lowproduced water flowrates, the producedwater treatment systems are capable oftreating well treatment, completion andworkover fluids without upset to theproduced water treatment system. Forthose facilities considered by EPA topotentially be unable to commingle

these fluids without causing a treatmentsystem upset, EPA based compliancewith the BAT and NSPS limitations ontransporting these fluids to shore forrecycle and reuse, where appropriate, ordisposal.

The option prohibiting discharges offree oil under BAT and NSPS wouldachieve no incremental removal ofpollutants from this wastestream overand above the existing BPTrequirements, and ignores aneconomically and technologicallyavailable treatment alternative.Therefore, EPA rejected the nodischarge of free oil limitation for BATand NSPS.

In its preferred option for the March1991 proposal, EPA presented effluentlimitations for well treatment,completion, and workover fluids basedon requiring zero discharge of anyconcentrated fluids slug along with abuffer volume preceding and followingthe fluids slug. Fluids which did notresurface as a distinct slug wereproposed to comply with producedwater limitations. EPA has sincedetermined that a limitation whichrequires capturing a buffer volume oneither side of a fluids slug is nottechnologically achievable because it isnot always possible and may not beentirely effective. In commenting on theproposal, the industry characterizedcompletion and workover fluiddischarges as small volume dischargeswhich occur several times during theworkover or completion operationswhich can last between seven and thirtydays. Based on this information, EPA nolonger considers the discrete slug andbuffer to be a proper characterization ofthe way workover, completion ortreatment fluids resurface from the well.Since the fluids often resurface slowlyand over a period of time, and are oftencommingled with the produced water,EPA considers treatment of these fluidscommingled with produced water in theproduced water treatment system to bethe appropriate technology.

EPA estimates peak BAT (first year)compliance costs of $1.7 million (1991dollars) and peak NSPS (year 15)compliance costs of $1.0 million. Forthose treatment, completion andworkover fluids which are commingledand treated with the produced water,non-water quality environmentalimpacts will be negligible based oncomparison of the fluid volumes withproduced water volumes. For thosefluids expected to be transported toshore for disposal, some non-waterquality environmental impacts willoccur. The anticipated non-waterquality environmental 'impactsassociated with the BAT and NSPS



limits are considered acceptable. Thevolumes of treatment, completion andworkover fluids to be handled are small(250-300 barrels per event) and theregularly scheduled supply boats haveadequate space to transport thecontainers of spent fluids. Offshoreplatforms would have adequate spacefor storage of the spent fluids for theperiods when the supply boats are notscheduled for the platform or whenoffloading to the supply boats isinfeasible due to weather conditions.Onshore treatment and disposal of spentfluids by injection into undergroundformations at centralized treatmentfacilities will result in a small increasein energy requirements and airemissions. The total volume oftreatment, completion and workoverfluids generated (and thus that portionrequiring onshore disposal) is a functionof the number of producing wells anddrilling activity. EPA projects that thevolume of these fluids disposed ofonshore as a result of this rule will begreatest immediately after promulgation(141,000 bbl/yr) and decrease toapproximately 50,000 bbl/yr fifteenyears after promulgation. Fuelrequirements and air emissions wereestimated based on two reinjectionscenarios: (1) Two 235-HP dieselpumps with average injection pressureof 1,000 psig; and (2) one 165-HP dieselpump with average injection pressure of260 psig. Under the high pressurescenario, the peak year required 2,800gallons of diesel fuel and emitted 2.8tons of air pollutants, decreasing to1,000 gallons of diesel fuel and 1.0 tonof air emissions in year 15. For the lowpressure scenario, 700 gallons of dieselfuel were required and I ton of airpollutants emitted in the first year afterpromulgation, decreasing to 250 gallonsof diesel fuel and 0.4 tons of airemissions in year 15.

XII. Basis for the Final Regulation-Domestic Wastes

Under BCT and NSPS, EPA isprohibiting the discharge of all floating

* solids and incorporating requirementslimiting discharges of garbage asincluded in U.S. Coast Guardregulations at 33 CFR part 151. TheseCoast Guard regulations implementAnnex V of the Convention to PreventPollution from Ships (MARPOL) and theAct to Prevent Pollution from Ships, 33,U.S.C. 1901 et seq. Discharges of foamare also prohibited under BAT andNSPS. (The definition of "garbage" isincluded in 33 CFR 151.05.)

The limitations established are alltechnologically available andeconomically achievable and reflect theBCT, BAT and NSPS levels of control.

Under the Coast Guard regulations,discharges of garbage, includingplastics, from fixed and floatingplatforms engaged in the exploration,exploitation and associated offshoreprocessing of seabed mineral resourcesare prohibited with one exception.Victual waste (not ncluding plastics)may be discharged from fixed or floatingplatforms located beyond 12 nauticalmiles from nearest land, if such wasteIs passed through a comminuter or*grinder meeting the requirements of 33CFR 151.75. Section 151.75 requires thatthe grinders or comminuters must becapable of processing garbage so that itpasses through a screen with openingsno greater than 25 millimeters(approximately one inch) in diameter. Apermit promulgated by Region 6 for theWestern Gulf of Mexico OCSincorporates the Coast Guardregulations (57 FR 54642; November 19,1992). Discharge of foam in other thantrace amounts is included in this Region6 permit and the 1986 general permit forthe Gulf of Mexico OCS as a mechanismfor controlling detergents (51 FR 24922).

Since these BCT, BAT and NSPSlimitations for domestic waste arealready In either existing NPDESpermits or Coast Guard regulations,these limitations will not result in anyadditional compliance cost, oradditional non-water qualityenvironmental impacts. There are noincremental costs associated with theBCT limitations; therefore, it isconsidered to pass the two part BCTcost reasonableness test.

XIII. Basis for the Final Regulation-Sanitary Wastes

BCT and NSPS limitations for sanitarywastes in this rule are equal to thecurrent BPT limitations. Sanitary wasteeffluents from facilities continuouslymanned by ten (10) or more personsmust contain a minimum residualchlorine content of I mg/l, with thechlorine level maintained as close tothis concentration as possible. Offshorefacilities continuously manned by nineor fewer persons or only intermittentlymanned by any number of persons mustcomply with a prohibition on thedischarge of floating solids.

At proposal, EPA discussed theavailability of alternative treatment andcontrol options. No alternativetechnologies available for installation atthe offshore facilities were identified.EPA did consider the appropriateness ofrequiring operators to capture sanitarywastes and transport the wastes to shorefor treatment. Specific data were notavailable regarding the costs oftransporting sanitary wastes to shore fortreatment. EPA projected compliance

costs based on the costs of transportingdrilling wastes to shore (excluding thefee charged by onshore drilling wastedisposal facilities). These projectedcompliance costs, in conjunction withpollutant removal estimates, did notpass the BCT cost-reasonableness testsand therefore EPA decided not to baselimits on onshore disposal. EPA rejectedzero discharge of sanitary wastes underNSPS because such a limitation wouldin reality result in operators

transporting the wastes to shore fortreatment and subsequent discharge bypublicly owned treatment works(POTW) back into surface waters. Also,the zero discharge limitation wouldincur additional non-water qualityenvironmental impacts (from the vesseltraffic) and compliance costs.

Since there are no increased controlrequirements beyond those alreadyrequired by BPT effluent guidelines,there are no incremental compliancecosts or non-water qualityenvironmental impacts associated withBCT and NSPS limitations for sanitarywastes. Since these limitations are equalto BPT, they are available andeconomically achievable. In addition,the BCT limitation is also considered tobe cost reasonable under the BCT costtest. Since the POTW test result and theindustry cost-effectiveness test resultsare both zero (and therefore pass theirrespective tests), the limitation is costreasonable.

EPA is not establishing BAT effluentlimitations for the sanitary waste streambecause no toxic or nonconventionalpollutants of concern have beenIdentified in these wastes.

XIV. Economic Analysis

A. IntroductionEPA's economic impact assessment is

presented in the "Economic ImpactAnalysis of Final Effluent LimitationsGuidelines and Standards ofPerformance for the Offshore Oil andGas Industry" (hereinafter, "EIA"). Thisreport details the investment andannualized costs for the industry as awhole and the impacts of these costs onaffected projects, typical companiesInvolved in offshore oil and gas drillingand production operations, and futureoil and gas production from the offshore'region. The report also estimates theeconomic effect of compliance costs onFederal and State revenues, balance oftrade considerations, and inflation.

EPA has also conducted an analysis ofthe cost-effectiveness of alternativetreatment options. The results of thecost-effectiveness analysis are expressedIn terms of the Incremental costs perpound-equivalent removed. Pound-

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equivalents account for the differencesin toxicity among the pollutants.removed. Total pound-equivalents arederived by multiplying the number ofpounds of a pollutant removed by atoxic weighting factor. The toxicweighting factor is derived usingambient water quality criteria andtoxicity values. The toxic weightingfactors are then standardized by relatingthem to a particular pollutant, in thiscase, copper. Cost-effectiveness iscalculated as the ratio of incrementalannualized costs of an option to theincremental pound-equivalents removedby that option. This analysis, "Cost-Effectiveness Analysis of EffluedtLimitation Guidelines and Standards ofPerformance for the Offshore Oil andGas Industry" (hereinafter "CE report").is included in the record of thisrulemaking. Since the discharges are toa marine environment, salt-water toxicweighting factors were used whereverthey were available.

B. Economic MethodologyEPA developed 34 economic model

platforms to represent the diversity inoffshore platform size (i.e.. number ofwell slots per platform), geographiclocation (Gulf of Mexico, Pacific, andAlaska), and production type (oil only,gas only, or both). Distinct technical andeconomic characteristics weredeveloped for each model. Costs.included in the models are thoseassociated with exploration,development, and production, as well asthe costs needed to meet currentregional permit requirements. Costs andrevenues were estimated over the life ofthe project based on currentrequirements to establish baselinefinancial summary statistics, such aseconomic lifetime, production,corporate cost per BOE, net presentvalue, and internal rate of return. Eachof these parameters varies by mqdelproject.

Then, capital and annual O&M costsassociated with various options wereadded to the baseline costs. The modelrecalculates the economic lifetime of theproject, annualizes the regulatory costsover the new project lifetime, andrecalculates production and financialsummary statistics. Project impacts wereevaluated by determining the changefrom the baseline values caused by theincreased regulatory costs, rather thanon the baseline values themselves. Costswere summed over all projects toprovide total capital, annual, andannualized costs of the regulation.

EPA developed two representativecompany financial profiles-one formajor integrated companies and one forindependent oil companies-to assess

the impact on oil and gas companiesoperating in the offshore area. Pre- andpost-regulation balance sheets weredeveloped for the typical companies.The impacts of the regulatory. costs onthe financial health of the companieswere investigated by the change infinancial ratios caused by those costs.

Production losses include thosereductions in hydrocarbon extractionresulting from immediate closure ofexisting projects, new projects that arenot undertaken, and curtailed lifetimes.These were based on the change inproduction and net present values forthe projects induced by the regulatorycosts. That is, if a project becameunprofitable with the additional costs, itwas assumed to close or not beundertaken.

EPA also analyzed secondary impactsof the regulation. These include:Revenue loss to the federal governmentdue to tax shields on expenditures,revenue loss to federal and stategovernments through potentially lowerbonus bids for new offshore projects,changes in the balance of trade,inflation, and impacts on related serviceindustries.

C. Summary of Costs and EconomicImpacts

1. Basis of the AnalysisThe economic analysis has four major

components: (1) An estimate of existingand projected structures that incur costsunder this rule; (2) use of an economicmodel to evaluate per-project impactsand annualize capital costs andoperating and maintenance costs; (3) anaggregate of the annualized costs toestimate the total costs for theregulation; and (4) an evaluation of theimpacts of those costs on typicalprojects, typical companies, future oiland gas production, Federal and Staterevenues, balance of trade, and othersecondary effects.

In response to comments received onthe 1991 proposal, changes were madeto the economic analysis. These changesinclude:

* The inclusion of existing structurescurrently in production in State waters of theoffshore subcategory in the Gulf of Mexico(affects BAT profile).

* A re-evaluation of the profile of existingstructures off California (affects BAT profile).

# Considering only the $21Fbbl oil price.constrained development scenario (affectsNSPS profile).

* Consideration of additional boundariesat 3-miles (for all effluents) and 8-miles (fordrilling fluids and drill cuttings, only), inaddition to the 4-mile boundary presented inthe March 1991 proposal.

e Inclusion of compliance costs for wastestreams previously believed to incur

negligible costs, e.g., treatment. workover,and completion fluids; and produced sand.(The selected options for deck drainage,domestic wastes, and sanitary wastes are stillassumed to create no additional costs andthus incur no impacts.)

The base year for the economicanalysis is 1986. This was set for the1988 Notice of Data Availability, whenit was the most recent year for which acomplete set of cost, revenue, and futureproduction data were available. In otherwords, a consistent set of data wereused to develop the economic modelsrepresenting typical projects in thatprofile. This "snapshot" in time wasmaintained for several reasons. First, theeconomic impact analysis examines thechange from the baseline values causedby the incremental costs of pollutioncontrol, rather than focusing on thebaseline values themselves. Second,1986 represents a recent nadir for the oilindustry in terms of oil prices, revenues,and financial health. Third, notchanging the baseline values of theeconomic models allows a clearerunderstanding of the changes caused byrecosting, different boundaries, andother factors listed above. Fourth, EPAevaluated the changes to the profiles ofnew drilling activity and productionstructures when the 15-year period ofthe analysis was shifted into the future(1991-2005 and 1993-2007) and foundthat the results varied minimally(within 3 percent) around the originalprofile (see sections I.B.2 and V.F.);and therefore the 1986 projectionremains valid for the 15 year periodfollowing promulgation. Costs arepresented here in 1991 dollars. Wherecost components have increased in time,the Engineering News RecordConstruction Cost Index is used toinflate 1986 dollars to 1991 dollars (seeEIA for details).

The industry profile used in thisanalysis is presented in section V.F.EPA estimates 2,549 existing structureswill incur compliance costs under theBAT regulations of this rule. It isestimated that a total of 759 newdevelopment and production structureswill be installed during the 15-yearperiod following promulgation. Thecosts for these new structures areassigned as NSPS compliance costs.

The number of wells drilled can varywidely from year to year. EPA estimatedthe total number of wells drilled duringa 15-year period after the regulationgoes into effect and then divided thattotal by 15 to obtain an average annualnumber of wells drilled. The averageannual number of wells drilled is 759wells per year. (It is coincidental thatthe average number of new wells drilledannually is equal to the total number of



new development and productionstructures to be installed over the next15 years.) About one-third of new wellsare projected to be classified as existingsources because they are exploratory Innature or will be drilled from existingstructures. Since the difference indrilling waste compliance costs for newand existing sources is negligible(because they comply with the samerequirements), the incremental costs fordrilling waste options do not depend onwhether they are BAT wells or NSPSwells.

2. Total Costs and Impacts of theRegulations

The total costs and impacts of theregulations combine the BAT and NSPScosts for all waste streams. BAT costsare highest infthe first year followingpromulgation when, for the purposes ofthe analysis, all existing sources incurcosts to upgrade their pollution controlsystems. These annualized costs willdiminish in time as these projects cometo the end of their economic life. NSPScosts, on the other hand, are small inyear 1 but are assumed to grow annually

until they peak in the 15th yearfollowing promulgation at which timethe rate of new source facilities ceasingproduction will equal, or exceed, therate of new sources coming Intoproduction. Adding the two sets of peakcosts would overstate the impacts sincethe peaks occur 15 years apart. EPAtherefore looked at the impacts in yearI and year 15. The cost components aresummarized in Table 10. The combinedannualized cost for the selected optionsis $134 million in year I and $38million in year 15 (1991 dollars).

TABLE I 0.--COMBINED COST OF FINAL RULE[1991 dollars, thousands)

Annualized AnnualizedWaste. stream Control option cost In year cost in year fit-

one teen

Drilling fluids & drill cuttings ....................................................................... 3 m ile GuWfCA ............................................................... 18,954 18,954BAT produced water .................................................................................... Flotation al .................................................................... 108.400 0NSPS produced water .................................................................................. Flotation all .................................................................... 907 13,605BAT treatm ent & workover fluids ........................ ; ........................................ ON & grease lim itations ...................................... ....... 1,693 0NSPS treatm ent & workover fluids .............................................................. Oil & grease lim itations .............................................. 0 842NSPS com pletion fluids ................................................................................ Oil & grea se limitations ................................................. 210 210Produced sand ............................................................................................. Zero discharge .............................................................. 4.127 4,127

Total com bined cost (before taxes) .................................................... ........................................................................................ 134,29 37,738

-Net cost to Industry will be lowered by tax savings realized. These tax reductions have been Included In estimates of federal revenue losses.Note: No Incremental compliance costs are Incurred-for deck drainage, domestic wastes and sanitary wastes.

EPA examined the combined effect ofregulatory options on BAT and NSPSprojects. The BAT models begin at theprojects' economic midlife, a time atwhich most drilling programs have beencompleted. For an existing single-wellstructure in the Gulf of Mexico with itsown production equipment (Gulf-lb)which is assumed to add-on a flotationsystem, the combined effects of theselected options for produced water,treatment and workover fluids, andproduced sand is expected to reduce thenet present value by 40 percent andincrease the corporate cost per barrel-of-oil-equivalent (BOE) by 28 percent.(This model project, termed Gulf-lb, isconsidered indicative of offshore-projects most sensitive economicallybecause its source of revenue is a singleproducing well. Most offshore platformsproduce hydrocarbons from multiple.wells.) For a Gulf of Mexico projectcomprising 12 well slots and 10peroducing wells, the same requirementsead to a four percent decline in net

present value and an increase of threepercent for the corporate cost per BOE.(This model, termed Gulf-12, Isconsidered representative of a typicaloffshore platform.) There were noproduction losses beyond those alreadyseen with the produced water option.

In evaluating the economic impacts ofthe rule on new projects, EPA included

the costs of increased pollution controlrequirements for drilling fluids, drillcuttings, completion fluids, producedwater, treatment and workover fluids,and produced sand. Althoughexploratory wells are always defined asexisting sources under the rule, thedrilling fluids and drill cuttingscompliance costs associated withexploratory wells are incorporated intothe NSPS models. Since the economicimpact models are designed to estimateimpacts and viability on a per-projectbasis, including in the NSPS model theexploratory efforts (wells) conducted toidentify and quantify producible oil andgas deposits is appropriate and allowsEPA to fully consider the effects onfinancial ratios.,

For a Gulf-lb project, the combinedcosts lead to a 2 to 5 percent increasein the corporate cost of production,depending on whether new equipmentis needed. If new equipment is needed,the net present value becomes negative.These projects are assumed to becanceled and production is lost. If newequipment is not needed, the netpresent value for the project remainspositive, but with a 65 percent declinein value from the baseline. For a moretypical Gulf-12 project, the samerequirements lead to decrease in netpresent value of 5 to 6 percent, and an

increased corporate cost of I to 1.5percent per BOE.

In the real world, there will beprojects that fall between the BAT andNSPS models, e.g., platforms that areinstalled prior to promulgation butcomplete part of their drilling programafter this rule is issued. These platformsare much closer to the beginning of theireconomic life than to their midpoint butnot all wells on the platform will havebeen drilled under the new BATrequirements. For these platforms, theper-project impacts are estimated to beequal to or less than the BAT per-projectimpacts, depending upon the number ofwells drilled under the newrequirements.

The year 1 costs are estimated toreduce the working capital of a typicalmajor oil company by 0.5 percent.(Working capital is the financial ratiomost sensitive to increased costs.) Foryear 15, the working capital decreasesby 0.1 percent. For a typicalindependent oil company workingoffshore, the year 1 costs would reduceworking capital by nearly 5 percent. Theyear 15 costs would reduce the workingcapital by about 1.4 percent.

Potential production losses aremeasured over the entire 15-year timeperiod of the analysis. Production lossesresult from shortened economiclifetimes, immediate shut-down ofexisting projects, and cancellation of

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new projects. Impacts associated withthe final rule would result in thepotential loss of 0.1 percent of theenergy expected to be produced by theOffshore subcategory over the 15-yearperiod (cumulative total ofapproximately 15.3 million BOE).

The selected options potentially couldresult in a $129 million (year 1) to $38million (year 15) loss to federalrevenues through tax effects and lowerlease bids (1991 dollars). Losses to staterevenues due to a potential lowering oflease bids ranges from $8 million (year1) to $2 million (year 15; 1991 dollars).The impact of this potential loss in staterevenue is minimal when compared tototal state revenue representing, forexample, less than 0.04 percent of totalstate revenues in Texas. Furthermore,these are potential losses. Companiesmay not choose to recoup all the costincrease through lower lease bidsbecause if the bids are too low,companies might not win the lease.Therefore, companies may absorb theentire compliance cost of the regulationthrough reductions in profits. In otherwords, the impact on federal and staterevenue would depend upon the actionthe companies may take through thelease bids--absorb the costs by notlowering the lease bids or pass on thesecosts through lower lease bids. Theactual impact on revenues wouldprobably be somewhere in thisestimated range but is hard to predict atthis time.

The final rule is not expected to affectenergy prices, inflation, employment, orinternational trade. The selected optionsmay, in fact, lead to positive impacts inthe offshore service industry due toincreased use of the service vessel fleet,onshore treatment/disposalrequirements, and the need to retrofit orupgrade some existing treatmentsystems. EPA finds the costs of the finalBAT and NSPS regulations to beeconomically achievable for the oil and

,gas industry.

D. Drilling Fluids and Drill CuttingsBAT limitations and associated

compliance costs for drilling fluids anddrill cuttings are the same for BAT andNSPS wells. Because there is no •difference between BAT and NSPSrequirements for drilling wastes, EPA'sanalysis shows that the economicimpact of the BAT limitations fordrilling fluids and drill cuttings is thesame as the impact of the NSPSlimitations discussed below. For thesereasons, the costs, cost-effectiveness,and economic achievability for BAT andNSPS drilling fluids and drill cuttingslimitations are presented on a combinedbasis. The projections of future activity

estimate that, on the average, 759exploratory, delineation, anddevelopment wells will be drilledannually for the 15-year period of theanalysis.

No capital costs are associated withthe options for drilling fluids and drillcuttings because oil companies that drilloffshore typically do not purchasevessels for transporting the wastes, butinstead contract that service. Theannualized cost of limits on drillingfluids and drill cuttings in this final ruleis $19 million, of which about one-thirdor $6 million is estimated to be the BATportion of the costs (1991 dollars). Fornew and existing oil and gas Gulf-12model platforms, the net present valuedecreases by 0.6 percent while thecorporate cost per BOE increases 0.1percent. For the model single-wellstructure with its own productionequipment (Gulf-lb), the drilling wastelimitation decreases the net presentvalue by 7 percent while the corporatecost of production increases by 0.2percent. None of the options consideredin this rulemaking for drilling fluids anddrill cuttings has an adverse impact onhydrocarbon production.

The BAT and NSPS limitations of thefinal rule are projected to reduce theworking capital of a typical majorcompany by 0.1 percent and theworking capital of a typical independentcompany by 0.7 percent. According toEPA's analysis, the rule would have noeffect on oil and gas prices,employment, or international trade. EPAfinds the costs of the selected option forBAT and NSPS control of drilling fluidsand drill cuttings to be economicallyachievable.

BCT limitations for drilling fluids anddrill cuttings within 3 miles from shoreare equal to BAT and NSPS limits.Beyond 3 miles from shore, only theprohibition on discharges of free oilapplies to BCT. Thus, compliance costsfor BCT do not include the cost ofsubstituting clean barite for dirty barite,monitoring costs for toxicity or dieseloil, or onshore disposal costs for drillingwastes failing the toxicity and diesellimitations.

On a per-well basis, the transportationand onshore disposal costs for BCT isequal to the BAT and NSPS costs. Asdiscussed above, BAT and NSPS costsfor drilling fluids and drill cuttings areeconomically achievable. Consequently,the BCT costs are also economicallyachievable. The BCT limitations passedthe two part BCT cost reasonablenesstest.

E. Produced Water

1. BCT

As discussed in section XI.A, BCTlimitations for produced water are equalto BPT. Therefore, there are noincremental costs and no economicimpacts for produced water BCTlimitations.

2. BAT

The cost of compliance for producedwater limitations will be highest in theyear in which the regulation goes intoeffect, because all existing structuresmust either meet the new limits withtheir current equipment and operation,upgrade their equipment and operation,or cease discharges of producedwater.These impacts will diminish in time asexisting projects come to the end oftheir economic life. For BAT producedwater options, then, year 1 costs are thehighest costs.

Total capital costs of the BATlimitations set by this rule are estimatedto be $431 million. Annual operatingand maintenance costs of $52 millionalso includes costs for two years ofmonitoring radium content of theproduced waters. (This rule is notrequiring radium monitoring ofproduced water. Monitoring costs of$3.4 million per year (1991 dollars) forthe first two years of the analysis wereincluded in the economic impactanalysis to project impacts of such amonitoring requirement on facilities andcompanies. A radium monitoringrequirement of finite, and relativelyshort-lived, duration is moreappropriately implemented bypermitting authorities and is not part ofthis regulation.) The annualizedincremental cost in year 1 of theregulation is estimated to be $108million and declines to zero in year 15.(All costs are in 1991 dollars.)

The EIA includes impacts of theoptions considered on each type ofmodel platform. Selected impacts andmodel platforms are presented here fora Gulf-12 oil and gas platform (10producing wells) and an oil and gasproducing single-well structure with itsown production and treatmentequipment (Gulf-lb model, consideredmost sensitive to the costs of theregulation). For an existing Gulf-12platform needing new treatmentequipment to comply with the effluentlimits of this rule, the net present valueof the project declines by 3.6 percentwhile the corporate cost per BOEincreases by 2.7 percent. For an existingGulf-lb platform, the net present valuedeclines by 35 percent, the corporatecost per BOE increases by 25 percent,and the project is assumed to cease



production operations one year earlybecause of increased annual costs ofoperation. The total loss in futurehydrocarbon production from existingstructures due to increased regulatorycosts from the rule is approximately 0.4percent (14.7 million BOE) over the 15-year period analyzed.

The BAT limitation of this rule leadsto an estimated decrease of less than 0.5percent in the working capital of atypical major company engaged in -offshore energy production and isprojected to reduce the working capitalof a typical independent company by3.7 percent. EPA finds the costs of thefinal BAT limitations for producedwaters to be economically achievable forthe oil and gas industry.

3. NSPSNSPS costs are small in the first year

of the regulation, covering only thestructures installed that year. NSPScosts continue to grow over time asmore structures are installed. By thefifteenth year, the number of new sourceplatforms going out of production isassumed to equal, or exceed, thenumber of new source platformsbeginning production. Thus, the cost inthe 15th year of the regulation isassumed to represent a peak NSPS cost.The total capital cost for the selectedoption is $96 million while the annualoperating and maintenance costs are $6million. The annualized cost in the 1styear is $1 million and $14 million in the15th year. (All costs are in 1991 dollars.)

For a new Gulf-12 platform, the limitson produced water set by this rule areestimated to decrease the net presentvalue by 1.4 percent while the corporatecost of production increases 0.5 percent.The NSPS economic models consider allcosts from lease purchase, throughplatform installation, and operation.The BAT model considers only the costof continuing operations past itsmidlife. For a single-well structure thathas its own production equipment (i.e.,a Gulf-lb), the net present value issmaller for the NSPS project than for theBAT project. This indicates that by themid-life of a single well structure, theinitial costs still have not beenrecovered. Under these circumstances,the same absolute decrease in netpresent value will appear as a greaterimpact on the NSPS project because ofthe smaller baseline value. This is whatis seen under the selected limitations forthis rule; the net present value for thesingle-well structure declines by 66percent under NSPS. while thecorporate cost of production increasesby 3 percent. If new equipment isneeded, the single-well project maycease production a year early. Loss of

future production over the 15-yearperiod due to early closures is estimatedat less than 0.1 percent (0.5 millionBOE) of the production from newstructures.

The selected NSPS limits forproduced water would have virtually noimpact on the working capital of atypical major oil company involved inthe offshore and would reduce theworking capital of a typical independentby 0.5 percent. According to. EPA'sanalysis, the selected limitations wouldhave no effect on oil and gas prices,employment, or international trade. EPAfinds the cost of NSPS for producedwater to be economically achievable forthe oil and gas industry.

F. Produced Sand

The annual compliance cost forproduced sand from BAT and NSPSsources under the selected option isestimated at $4 million (1991 dollars).No capital investments are expected tobe associated with the limitations forthis waste stream. The transport of theproduced sand to shore and itssubsequent disposal is assumed to becontracted to another companysupplying such services. For BATmodels, the financial summary statisticschange by no more than 0.7 percent andthere is no estimated loss in production.For NSPS models, if produced sandfrom a single-well structure (Gulf-lbmodel) contains elevated levels ofNORM (naturally occurring radioactivematerial) such that disposal'at a low-level radioactive disposal site isrequired, the net present value maydecrease by 3 percent. For all otherfinancial statistics and all other projects,the parameters change by no more than0.5 percent There is no loss ofproduction associated with thislimitation. The costs lead to negligiblechanges in financial ratios for typicalmajor and independent oil companiesengaged in offshore oil and gasproduction. EPA finds the costs of theBAT and NSPS zero dischargelimitations for produced sand to beeconomically achievable.

G. Well Treatment, Completion andWorkover Fluids

1. BCT

As discussed in sectiost XI, BCTlimitations for well treatment,completion and workover fluids areequal to BPT. Therefore, there are noincremental costs and no economicimpacts associated with the BCTlimitations for these wastestreams.

2. BAT and NSPSExisting wells will bear the costs of

additional controls on treatment andworkover fluids prior to discharge.Larger structures are assumed togenerate enough produced water thattreatment and workover fluids can betreated within the produced watersystem without upset and withoutadditional costs. Smaller structures,which may be unable to process thefluids without treatment system upsets,bear the costs of segregated treatmentand workover fluid disposal.-As withproduced water, the cost of BATlimitation on oil and grease fortreatment and workover fluids is highestin the first year of the regulation, whenall existing wells are covered, and willdecrease in time as the wells becomeunproductive and cease operations. Thefirst year costs for BAT treatment andworkover fluids is $1.7 million (1991dollars). The changes in the per-projectnet present value and corporate cost perBOE are small, about 1 percent or lessfor all projects investigated. The costs ofthe BAT limitations for control oftreatment and workover fluids areeconomically achievable.

Each new productive well drilled willneed to meet the limitations oncompletion fluids. Once in production,these wells are anticipated to requiretreatment or workover on the average ofonce every four years. The treatmentand workover fluids, like thecompletion fluids, must meet new limitson oil and grease. Larger structures areassumed to generate sufficient volumesof produced water to commingle thesewaste streams without upset to theproduced water treatment system, soincremental costs would be borne onlyby smaller projects. The annualcompliance cost for completion fluids Isestimated at $0.2 million. Thecompliance costs for treatment andworkover fluids would begin atnegligible levels when the regulationfirst goes into effect and would peak at$0.8 million In the 15th year. (Costs arein 1991 dollars.) The financial summarystatistics for all economic modelschange by less than 1 percent and thereare negligible impacts on companyfinancial ratios. EPA finds the BAT andNSPS limitations for treatment,workover, and completion fluids to beeconomically achievable.

H. Deck Drainage, Sanitary, andDomestic Wastes

The new limitations for thesemiscellaneous waste streams have noassociated increase in compliance costsbecause they are either the same as BPT,permit requirements, or U.S. Coast

12491



Guard limits. Therefore, there are noassociated economic impacts.

I. Cost-Effectiveness AnalysisIn addition to the foregoing analyses,

EPA has performed a cost-effectivenessanalysis for the selected options fordrilling fluids and drill cuttings,produced water, and produced sand.According to EPA's standard proceduresfor calculating cost-effectiveness, all theoptions considered for each wastestream have been ranked in order ofincreasing pounds-equivalent (PE)removed (see the introduction to thissection for a discussion of pounds-equivalent, a methodology for puttingpollutants of differing toxicity on acomparable basis.) The cost-effectiveness value calculated forproduced sand includes only theestimated pollutant removals forradium. EPA believes that had specificdata on other known constituents(heavy metals and organics) in producedsand been available, the cost-effectiveness for produced sandlimitations in the rule would beconsiderably less than the reported $291per pound-equivalent. Cost-effectiveness is calculated as the ratio ofthe incremental annual costs to theincremental pounds-equivalent removedfor each option. So that comparisons ofthe cost-effectiveness among regulatedindustries may be made, annual costsfor all cost-effectiveness analyses arereported in 1981 dollars.

In 1981 dollars, the incremental cost-effectiveness for the selected optionsare:-$44/PE--drilling fluids and drill

cuttings-$33/E-BAT produced water-$17/PE-NSPS produced water-$291/PE-produced sand (only

radium removal was used to calculatepound-equivalent of pollutantreduction for this waste stream).

J. Regulatory Flexibility ActThe Regulatory Flexibility Act, 5

U.S.C. 601 et seq., requires that EPAprepare a Regulatory FlexibilityAnalysis (RFA) for regulations that havea significant economic impact on asubstantial number of small entities.This analysis may be done in "conjunction with or as a part of anyother analysis conducted by EPA. Thepurpose of the RFA is to ensure that,while achieving EPA's statutory goals,the Agency has considered regulatoryoptions for minimizing the cost ofcompliance on small entities.

The economic impact analysisdescribed above indicates that theexpenses necessary to meet the finaleffluent limitations guidelines and

standards for the offshore oil and gasindustry will be incurred by major andindependent oil companies. These arenot "small entities" by any standard.Additionally, the analysis hasdetermined that none of the companiesdirectly affected by this rule are smallentities. Therefore no formal RegulatoryFlexibility Analysis was proposed andEPA certifies that this rule will not havea significant economic impact on asubstantial number of small entities.

K. Paperwork Reduction ActToday's rule places no additional

information collection or record-keepingburden on respondents. Therefore, aninformation collection request has notbeen prepared and submitted to theOffice of Management and Budget(OMB) under the Paperwork ReductionAct, 44 U.S.C. 3501 et. seq.

XV. Executive Order 12291

A. IntroductionExecutive Order 12291 requires the

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

The RIA analyzes the effect of currentdischarges and benefits of finallimitations for the major waste streamsfrom offshore oil and gas drilling (e.g,drilling fluids and drill cuttings), andproduction activities (e.g., producedwater) on the offshore environment.Three types of benefits are analyzed:quantified and monetized benefits,quantified and non-monetized benefits,and non-quantified and non-monetizedbenefits.

The monetized benefits analysisfocuses on the human health-relatedbenefits of the regulatory optionsconsidered. These health risk reductionbenefits are associated with reducedhuman exposure to various carcinogenicand noncarcinogenic contaminants,including lead, by way of consumptionof shrimp and recreationally caughtfinfish from the Gulf of Mexico. Majortoxic effects by lead in humans includeinhibition of heme synthesis, kidneydisfunction, and damage to the centralnervous system. Broad symptomsinclude increased blood pressure andreduced learning ability. The leadrelated benefits include: (1) Decreasedinfant mortality; (2) reduced I.Q.

impairments in children; and (3)reduced risks of hearth disease, strokes,hypertension and death. All benefitswere estimated using a saltwater leachscenario for calculating thebioavailability of lead in the marineenvironment.

Other benefits that are quantified, tothe extent possible, but not monetizeddue to lack of appropriate data, include:(1) Human health risk reductionsassociated with systemics other thanlead, pH-dependent leach rates,carcinogens for which there are no riskfactors available, exposure to pollutantsvia sediment or food chair, (2)ecological risk reductions; (3) fisherybenefits; and (4) intrinsic benefits.

The combined monetized benefits ofregulating drilling fluids, drill cuttings,and produced water in the offshoresubcategory of the oil and gas extractionindustry are found to be reasonablycommensurate with their costs. Thetotal monetized benefits for selectedoptions (in 1991 dollars for the Gulf ofMexico only) range'from $28 to $104million annually. Hypertension effectswere estimated based on a dataset witha median blood lead concentration of 15pg/dL. Average blood leadconcentrations are around 4.5 pg/dL.There may be uncertainty associatedwith the estimate of hypertensioneffects, because EPA has assumed thatthe relationship between hypertensioneffects at 4.5 jg/dL is the same as the15 ig/dL blood lead concentration. Themonetized benefits associated withhypertension risk reduction are $0.2million. The total annualized BAT andNSPS costs in the Gulf of Mexico are$122 million in the first year anddecline to $32 million in the 15th yearfollowing promulgation. Quantified-monetized benefits are based solely onthe predictive health-related impacts.Benefits associated with regulatingdrilling fluids and drill cuttingspredominate over those associated withregulating produced water; for drillingfluids and drill cuttings, lead-relatedbenefits predominate over carcinogen-related health benefits.

The quantified, non-monetizedbenefit assessment includes a review ofcase studies of environmental Impactsof drilling fluids and drill cuttings andproduced water that document adversechemical and biological impactsresulting from discharge of these wastesin the Gulf of Mexico, Atlantic,California and off Alaska and waterquality analysis. A comprehensivereview of available data (over 1000references, plus EPA's Ocean DataEvaluation System (ODES) database)show documented local impacts fordrilling fluids and drill cuttings



discharges (22 case studies) and forproduced water discharges (7 casestudies). Geographically widespreadmarine impacts are not welldocumented. In preparing a waterquality analysis for this rule, EPA usedas a baseline permit conditions imposedby the Region 6 general permit for theOCS of the Gulf of Mexico, 51 FR 24897(July 9, 198*6). EPA projectedexceedences of marine water qualitycriteria and toxic benchmarks, whichare factors that EPA takes into accountin making a-determination of whether adischarge will cause unreasonabledegradation of the marine environment.See 40 CFR 126.122(a)(10).

Discharged drilling fluids and drillcuttings are shown to causecontamination of sediments with heavymetals and hydrocarbons up to 4000meters from the platforms. Otherdocumented impacts include decline inabundance of benthic species (up to1000 meters from the platform), reducedbryozoan coverage (within 2000 metersof discharge), altered benthiccommunities (up to 300 meters fromplatforms), bioaccumulation of heavymetals known to be present in drillingfluids and drill cuttings by benthicorganisms, complete elimination ofseagrass (within 300 meters ofdischarge), inhibited growth of seagrass(up to 3,700 meters, from the dischargepoint), and decreased coral coverage.

Produced water discharges are shownto cause contamination of sedimentswith metals and polynuclear aromatichydrocarbons (PA-) up to 1000 metersfrom the platforms. Other significantimpacts include reduction of benthicorganisms (to below background levels)up to 300 meters from platforms,alteration of benthic communities(mostly toward opportunistic species),and sub-lethal (chronic) impacts to biotaat distances in excess of 500 metersfrom the discharge point in high energy,open ocean environments.. The RIA uses models to project water

quality impacts based on section 403(c)marine water quality criteria and humanhealth risks from consumption of fish(consumed by recreational fishermen)and commercially caught shrimp(consumed by the general population) asa result of the offshore oil and gasdischarges from existing and newoffshore oil and gas platforms in theGulf of Mexico. The "baseline,"representing limitations under the 1986general permit for the OCS in the Gulfof Mexico, and regulatory optionsconsidered for BAT and NSPS limits areassessed. The Gulf of Mexico wasselected as a case study area becausemore than 90 percent of the offshore oiland gas exploration and production

activities occur in this region, andbecause of its importance forcommercial and recreational fishing.

The RIA attempted to quantify andmonetize the specific environmentalbenefits that may result from the optionsconsidered for this rule. However, thehigh dilution afforded by the marineenvironment resulted in modeledpollutant concentrations that weresufficiently low that no directlyquantifiable impacts on the Gulf ofMexico fishery could be attributed tothe platform-related discharges.Predictions could not be made toquantify direct impacts of currentdischarges and benefits of optionsconsiddred for this rule on compositionand abundance of finfish and shellfishpopulations, recreational fishing andother recreational activities, commercialfishing, or nonuse benefits. Therefore,the RIA for this rule focuses exclusivelyon the benefits associated with humanhealth risk reduction through modeledreduction in concentration of platform-related pollutants in recreationally-caught fish and commercially caughtshrimp. Both carcinogenic and systemic-human toxicant effects are considered.These quantified and monetizedincremental benefits are compared tothe annualized incremental cost in theGulf of Mexico for the BAT and NSPScontrol options considered for this rule.

The non-quantified, non-monetizedbenefits assessed in this RIA includeincreased recreational fishing, increasedcommercial fishing, improved aestheticquality of waters near the platform, andbenefits to threatened or endangeredspecies in the Gulf of Mexico.Recreational fishing benefits may berealized because (a) regulations maychange perceptions about the risk tohealth posed by fish caught near theplatforms, thus encouraging recreational

shing near the rigs and increasingfishing values; (b) to the extent anglersperceive that water quality near theplatforms has improved, they may fishmore often near the platforms thusincreasing their participation; and (c)reduced discharges may improve theecosystem in a way that enhances thefishery. For example, reduced pollutantconcentrations would positively affectlower-level organisms in the food chain,improve reproductive success, increasethe ability to avoid predation andimprove growth.

Since data are not available toevaluate these hypotheses, EPA has notpredicted potential recreational fishing

enefits. However, if the regulations dohave a positive impact on recreation,then the benefits of improvedrecreational fishing could be substantial.For example, even a 0.1 percent increase

in recreational value would increaserecreational fishing benejqts by about$12 to $14 million.

Non-use benefits associated withimproved water quality could bepotentially significant. In freshwatersettings, studies show that such benefitswere no less than 50 percent of theassociated recreational values.

The regulation may also have abeneficial effect on two federally-designated endangered species-theKemp's Ridley Turtle and the BrownPelican--that use the Gulf of Mexico aspart of their habitaL

The commercial fishery in the Gulf ofMexico is a vital component of theregional economy. While there are datato suggest correlation between oil andgas extraction activities and fisheriescatch statistics, definitive causalrelationships cannot be developed.However, indirect impacts on the size orcomposition of the fishery, or onconsumer demand for Gulf fisheryproducts, may generate commercialfishery benefits.-

B. Drilling Fluids and Dzill Cuttings

The water quality analysis isperformed for water column andsediment pore water quality impactsusing mean seawater leachability (withmean leach percentages experimentallyderived in seawater medium). Waterquality impacts and benefits areprojected for 23 pollutants representingaverage subcategory-wide drillingdischarges.

The estimated human health benefitsfor the BAT and NSPS drilling fluidsand drill cuttings limitations are in therange of $28 to $104 million (forseawater leach) compared to a projectedincremental annualized cost of $19million (in 1991 dollars for the Gulf ofMexico only) (Table 11) based on thecombined quantified average riskreduction associated with consumptionof fish and shrimp contaminated by leadand arsenic from drilling fluids and drillcuttings discharges. An additionalreduction in human health risk from thesubsistence fishing near the platforms isalso anticipated but could not bequantified by this RIA.

Table 11 .- INCREMENTAL ANNUAUZEDBENEFITS AND COSTS FOR DRILUNGFLUIDS AND CUTTINGS BAT/NSPS OP-"IONS[Millions of 1991 dollarser year Gulf of Mexico

f Annual bone- AnnualRegUlat Y option fits. cost

3 Mile GulfCAb............... $28.14103.6 1 $18.8

12493



Table 11.-INCREMENTAL ANNUALIZEDBENEFITS AND COSTS FOR DRILLINGFLUIDS AND CdII1NGS BAT/NSPS OP-TIONS-Continued[Millions of 1991 dollarsp year Gulf of Mexicoorgy)

8MZero

Regulatory option Annualene- Annualfits. cost

lIle Guf/3 Mile CA ..... 28.5-104.7 33.1re Dlscf.aroe Gulf/CA . 30.0-110.5 I142.4

*Relative to baseline of current practice.bRegulatory option selected for this rule.

C. Produced Water

The water quality analysis isperformed for water column water

quality impacts. Water quality impactsand benefits are projected for 29pollutants representing averagesubcategory-wide produced waterdischarges.

The estimated human health benefitsfor the BAT limitations of the final rule,based on the quantified average riskreduction associated with theconsumption of platform-contaminatedfish for three carcinogens (arsenic,benzene, benzo(a)pyrene) and onesystemic toxicant (lead), are estimatedto range from $30,000 to $123,000,versus a projected incrementalannualized cost of $102 million in thefirst year that declines to zero in the

15th year (in 1991 dollars for the Gulfof Mexico only) (Table 12). Theestimated human health benefits for theNSPS limitations (based on the samepollutants) are estimated to range from$39,000 to $162,000, versus a cost of $1million in the first year that rises to $13million in the 15th year (in 1991 dollars,for the Gulf of Mexico only) (Table 13).An additional reduction in humanhealth risk due to subsistence fishingnear the oil and gas platforms in theGulf of Mexico region is also anticipatedbut could not be quantified by this RIA.

TABLE 12.-INCREMENTAL BENEFITS AND COSTS FOR PRODUCED WATER BAT OPTIONS(Millions of 1991 dollars per year; Gulf of Mexico only)

Annualized cost Annualized costRegulaory option Annual benefits In year In year 15

Flotation An. ................................................................................................................................................ $0.030-4 0.123 $102.2 0.0

Zero 3 Miles Gulf and Alaska4 ..................................................................................................................... 0.28-1.42 123.8 0.0Zero Discharge Gulf and AlaskaI .............................................................................................................. 0.54-2.78 730.3 0.0

Relative to baseline of current practice.',Regulatory option selected for this rule.

Benefits associated with controlling Ra-226 and Ra-228 are considered only for options that Include zero discharge.

TABLE 13.-INCREMENTAL BENEFITS AND COSTS FOR PRODUCED WATER NSPS OPTIONS[Mllions of 1991 dollars per year; Gulf of MexIco only]

Annualized cost Annualized costRegulatory op in year 1 in year IS

Flotation A" b

............................ ............. ................................................................................. ................... $0.0 "9 $ .16 $0.9 13.4

Zero 3 MIles Gulf and Alaska' ................................................................................................................... 0.30-1.5 3.9 57.7Zero Discharge Gulf and Alaska, ................................................................................................................ 0.55-2.8 25.0 375.5

Relative to baseline of current pracce.6Regulatory option selected for this rule.

Benefits associated with controlling Ra-228 and Ra-228 are considered only for options that Include zero discharge.

XVI. Public Participation and Summaryof Responses to Major Comments

Public participation in thedevelopment of the effluent limitationsguidelines and standards for thisindustry has been extensive.Throughout the development of thisregulation, EPA has made numerousdocuments available to the public forcomment and has held public meetingsfor the purpose of providing informationand receiving information and viewsfrom many individuals andorganizations.

The public comment period for the1985 proposal, set originally for threemonths, was extended to provide a totalof six months for comment. Partly inresponse to these comments and partlyto incorporate supplemental data, EPAmodified its data base, methodologiesand regulatory approaches anddiscussed these changes in a Notice ofAvailability and request for commentson October 21, 1988 (53 FR 41356). Thecomment period for this Notice of

Availability, originally set for six weeks,was subsequently extended to provide atotal of three months for comment.

On November 26, 1990 (55 FR 49094),EPA published a proposal andreproposal presenting additionalmodifications to the data base andchanges to methodologies andregulatory approaches. A one monthcomment period was provided for thisproposal.

On March 13, 1991 (56 FR 10664),EPA published a subsequent proposaldescribing the November 1990 proposalin greater detail and setting forthadditional technical, economic,environmental, and other informationrelating to the establishment of effluentguidelines and standards for theoffshore subcategory. The commentperiod for this proposal was originallyset for one month. EPA subsequentlyextended the comment period for themajority of the proposal by anadditional month, with several keyissues extended to provide a total of

three months to comment. In responseto the notices and proposals discussedabove, EPA received 145 submissions ofcomments and data from industry,government, environmental and othergroups, and individuals. Thesesubmissions comprise over 5,000 pages.

Throughout this rulemaking, EPA hasnot only welcomed the submission ofcomments, but also solicited data thatcould be used to supplement, correct, orfill gaps in EPA's data base. Whereadequately documented data ofsufficient quality were submitted, EPAused the data along with other data ithad collected. EPA believes that It hasmade all reasonable efforts to obtainpublic input on this rule.

Included in the record for this rule isa large response to comments document.The sheer volume of commentsprecludes the publication of EPA'sresponses to all of them in thispreamble. EPA has discussed andresponded to some comments earlier inthis preamble. Other comments are



responded to in the separate response tocomments document mentioned above.Finally, the various data compilations,editing, and other informationcontained in the record for this ruleaddress (and in some instances wereobtained or acquired specifically for thepurpose of addressing) the publiccomments.

A. Cadmium and Mercury BAT andNSPS Limitations for Drilling Fluids andDrill Cuttings

Comment: Several commentersexpressed opposition to establishingBAT and NSPS limitations on cadmiumand mercury In drilling fluids and drillcuttings wastestreams at 1 mg/kg each,as measured in the whole drilling fluid.The commenters cited data indicatingthat the geologic formation can act as acontributor of cadmium to the drillingfluid, and recommended establishingthe metals limits in the stock bariterather than "end-of-pipe." Someindustry commenters suggested a stockbarite limitation of 3 mg/kg cadmiumand 1 mg/kg mercury, while otherssuggested a limit of 5 mg/kg cadmiumand 3 mg/kg mercury in the stock barite.

Response: EPA agrees that thelimitations on cadmium and mercuryshould be set in the stock barite. Thefinal BAT and NSPS limits for drillingfluids and drill cuttings includelimitations on cadmium and mercury at3 mg/kg and I mg/kg (dry weight),respectively, in the stock barite. This isnot an effluent limit to be measured atthe point of discharge, but a standardpertaining to the metals content of thebarite used to formulate drilling fluids.Compliance with the limitation wouldinvolve the use of barite from sourcesthat either do not contain these metalsor contain the metals at levels below thelimitation.

EPA has analyzed data from theAmerican Petroleum Institute's FifteenRig Study. In this study, samples of drillcuttings, used drilling fluid, and baritefrom a number of drilling sites weresampled for metals content. Results ofEPA's statistical analysis indicate thatsome cadmium present in the drillingfluids came from a source other than thebarite.

Establishing the final metalslimitations on the stock barite, ratherthan "end-of-pipe" in the whole drillingfluid at the point of discharge, isconsistent with EPA's original intent forcontrol of drilling fluids and drillcuttings. EPA's technology basis forlimits on metals content in drillingwastes has always been productsubstitution of "clean" barite sourcescontaining low levels of impurities as asubstitute for "dirty" barite with higher

concentrations of impurities. In sectionVILB of the preamble, EPA discusseswhy the limits selected for the final'ruleare available and economicallyachievable.

B. Clearinghouse Approach forControlling Toxicity of Drilling Wastes

Comment: Several industry -commenters have stated that EPAshould use a "clearinghouse" approachto control toxicity for drilling fluid3 anddrill cuttings, rather than establish"end-of-pipe" toxicity limits. Instead ofmeasuring compliance through bioassayof drilling wastes, a clearinghouseapproach would project the cumulativetoxicity of the drilling fluids andadditives in advance based on mudformulation.

Response: In the 1985 proposal, oneof the options proposed for limiting thedischarge of muds was referred to as the"Clearinghouse/Toxicity Approach" (50FR 34592). The clearinghouse concept isbased on the fact that operationallysatisfactory drilling fluids can beformulated by substituting less toxicconstituents. Under a clearinghouseconcept, a list of effective muds thatcould be discharged from offshoreoperations would be compiled. Thegeneric drilling fluid concept wasdeveloped in 1978 when EPA instituted-a joint testing program for variousformulations for operations in theAtlantic Ocean lease sale areas. EPARegion 2 and the Offshore OperatorsCommittee (OOC) conducted the Mid-Atlantic Bioassay Program whichidentified eight water-based drillingfluid types (generic fluids) thatencompassed virtually all types ofdrilling fluids in use at the time. Thegeneric fluids were then bioassayedonce as an alternative to having theparticipating operators perform bioassayand chemical tests every time adischarge occurred. To allow for the useof acceptable additives in drillingoperations, EPA and the OOC alsodeveloped the concept of an "approved"additives list. An operator could submitbioassay data on a mud containing aparticular additive to EPA for review. IfEPA "approved" the additive, operatorswere then allowed to discharge thegeneric fluid types, including certainapproved specialty additives("additives"), without conductingadditional testing (50 FR 34603). OtherEPA Regions used the results from thegeneric fluids testing in permits issuedfor Outer Continental Shelf (OCS) leaseareas, and the 1985 proposal alsocontained another option (Option 1, 50FR 34607) which limited toxicity to30,000 ppm for the suspended

particulate phase (SPP) based on theresults of bioassay pro ram.

In the 1985 proposal, Option 2-Clearinghouse Approach discussed theestablishment of a nationalclearinghouse to be administered byEPA. Under this option, EPA wouldserve as a repository for all toxicity andrelated physical and chemicalcharacteristics of base drilling fluidformulations and additives. Theinformation would be used by thepublic and operators for use in selecting

uid/additive formulations that wouldlikely comply with the establishedtoxicity regulations (50 FR 34608).

EPA Region 10 later Issued severalNPDES general permits (Bering andBeaufort Seas (49 FR 23734, June 7,1984) Norton Sound (50 FR 23578, June4, 1985), Cook Inlet/Gulf of Alaska (51FR 35460, October 3, 1986), ChukchiSea and Beaufort Sea 11 (53 FR 37846,September 28, 1988)) in which thedischarge of certain additives wasauthorized without further bioassaytesting if discharged in generic drillingmuds. In all of its permits, Region 10authorized the discharge of certainmuds and a variety of specialtyadditives listed on tables in the permits.When operators needed to use muds oradditives not directly authorized on thetables, Region 10 evaluated availablebioassay data and authorized discharge(or not) based on its BPJ estimate of thecumulative toxicity for the proposeddischarge. Region 10 often requiredbioassay of the discharged muds/additives at maximum (discharge)concentrations in order to obtainbioassay data that represented practicalproduct concentrations and actualdischarge toxicity. Region 10's approachwas based on additivity (meaning thatthe toxicity of the whole drilling fluidcould be estimated based on the toxicityof the constituents) because there wereno other practicable ways in which toaddress available bioassay data.

In the 1985 proposal (50 FR 34592)and the 1991 proposal (56 FR 10664),EPA rejected the Clearinghouse optionbased on the time required to developsuch a program, and the complexity ofmanaging such a program on a nationallevel. Although EPA has receivedcomments in favor of a clearinghouseapproach to fluids/additive dischargeauthorization, several important reasonsremain that support rejection of thisregulatory op~tion.first, EPA s NPDES permitting

program (section 402 of the Act) isbased on point of discharge ("end-of-pipe") accountability. While bioassaysof drilling wastes to be disposed of arean established measure of compliancewith "end-of-pipe" toxicity limits, a

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clearinghouse approach would requirethe cumulative toxicity of the fluids andadditives to be projected in advance.These advance estimates would have tobe performed for each discharge ofdrilling fluids by hundreds of offshorewells annually. Whether EPA performsthe estimates or industry submits themfor Agency review, because of the largenumber of drilling operations in theoffshore subcategory the administrationof such a program would be complexand would place a huge administrativeburden on the Agency. Compoundingthis, EPA would be required to maintaina data base with up-to-date informationon fluids and additives, provide

resources to track the data, and respondto challenges to clearinghousedeterminations.

Although it has been demonstratedthat the clearinghouse systems can beeffective on a small scale, EPA hasreservations regarding the feasibility ofa nationwide program. The success ofthe Region 10 program is due, in largepart, to the relatively small number ofwells drilled in the past and estimatedfor the future. (The projected number ofnew drillings for the Region 10 offshorearea is 1Z per year). A nationalclearinghouse program involving over700 new drillings per year and requiringmaintenance and updating of a databasecontaining information on numerousadditives and fluids combinationswould be much more difficult tomanage and would place an enormousburden on the Agency.

For these reasons, EPA rejected theclearinghouse option as a component ofnationally applicable regulations;however, this would not necessarilypreclude EPA Regions from using aclearinghouse approach in permits as ameans of implementing the toxicitylimits in these regulations, ifappropriate.

C. Synthetic Drilling FluidsComment: Several industry

commenters noted recent developmentsin formulating new drilling fluidsystems (e.g. vegetable oils, synthetichydrocarbon-based fluids, polyolefins)as substitutes for the traditional water-based and oil-based (diesel or mineraloil) drilling fluids. Industry coomnenterscontend that the new drilling fluids arepotentially much less toxic than manyof the more traditional drilling fluidscurrently in use. However, the newerfluids are not being used because theyare costly and because they are likely tocause a discoloration on the receivingwaters. This discoloration may beinterpreted as a "sheen" which is themechanism specified for determiningcompliance with the existing BPT limit

and the BCT and BAT limits and NSPSestablished in this rule for no dischargeof free oil from drilling fluids and drillcuttings. The newer fluids may cause asheen even where there has been nodischarge of diesel or mineral oil orhydrocarbons from the well. In otherwords, the static sheen test cannotdistinguish between drilling fluids anddrill cuttings containing these newerdrilling fluids and drilling fluids anddrill cuttings contaminated by diesel oil,mineral oil. or formation hydrocarbons.For these reasons, industry commentersfurther contend that these newerdrilling fluids should be exempt fromcompliance with the no free oillimitation required by these effluentlimitations and NSPS.

Response: EPA disagrees with thecommenters' assertion that certaindrilling fluids should be exempted fromthe BCT and BAT limitations and NSPSestablished in this rule prohibitingdischarge of free oil in drilling fluidsand drill cuttings as determined by thestatic sheen test. The technology basisfor the no free oil requirement, onshoretreatment and/or disposal of drillingfluids and drill cuttings is applicable toall drilling fluid systems and preventsdischarge of substantial quantities ofconventional, non-conventional andpriority pollutants. The prohibition ondischarge of free oil was originallyestablished under BPT to preventdischarges of drilling wastecontaminated with diesel oil, mineraloil, or formation hydrocarbons tosurface waters. Since mineral oil ordiesel oil is occasionally added to adrilling fluid system to enhance*lubricity or as a pill to free stuck pipe,or hydrocarbons from the formation mayenter the drilling fluid system duringdrilling operations through oil-bearinggeologic strata, the prohibition ondischarges of free oil remains anappropriate limitation for discharge ofdrilling fluids and drill cuttings.

While EPA agrees that some of thenewer drilling fluids with non-mineraloil or non-diesel oil bases may be lesstoxic and more readily biodegradablethan many of the drilling fluidscurrently in use, EPA is concerned thatthere is no method for determiningcompliance with the no free oil standardto replace the static sheen test. In otherwords, if EPA were to exclude certainfluids from the requirement, therewould be no way to determine if at thatparticular facility, diesel oil, mineral oilor formation hydrocarbons were alsobeing discharged.

At the same time, EPA wants toencourage development of less toxicdrilling fluid substitutes or drillingfluids with a higher degree of

biodegradability if an alternativemethod can he developed to distinguishbetween discharge of diesel oil, mineraloil, or formation hydrocarbons indrilling fluids and drill cuttings fromdischarges of these newer drillingfluids. EPA solicits data on alternativeways to differentiate between these twokinds of discharges, including gaschromatography or other analyticalmethods EPA also solicits informationon technological issues, related to theuse of these newer fluids (e.g., underwhat geological conditions and for whatpart of the drilling operations can thesenewer drilling fluids be used), anytoxicity data or biodegradation data onthese newer fluids, and costinformation. EPA will consider thisinformation, and if appropriate, issueguidance on use of the static sheen testfor distinguishing these newer drillingfluids from mineral oil-based fluids,diesel oil-based fluids or formationhydrocarbons. Also, if appropriate, EPAmay propose alternative analyticalmethods or undertake other rulemakingto address this issue.

EPA acknowledges that the currentGulf of Mexico general permit prohibitsthe discharge of inverse emulsiondrilling fluids, which are defined as oil-based drilling fluids which also containa large amount of water. EPA solicitsinformation on whether newer drillingfluids should be considered inverseemulsion fluids and what effect thecurrent permit prohibition on dischargeof inverse emulsion fluids will have onthe ability to discharge newer, non-petroleum oil-based synthetic fluids ifthey pass the static sheen test, alongwith the other limitations applicable todrilling fluids and drill cuttings.

D. Non-Water Quality EnvironmentalImpacts-Drilling Wastes

EPA received several commentsregarding non-water qualityenvironmental impacts associated withthe limitations on discharges of drillingfluids and drill cuttings. Thesecomments related primarily to thevolumes of drilling fluids and drillcuttings that would need to be disposedand the number of vessels available totransport drilling fluids and drillcuttings to shore for disposal.

CommeM: EPA received commentssuggesting that the assessment of non-water quality environmental impacts(and any regulatory determination basedon these impacts) should be based ondrilling waste volumes which resultfrom operators using enhanced solidscontrol systems. The coenmentercontended that by basing drilling wastevolume estimates on enhanced solidscontrol system, the volume of drilling



wastes requiring onshore disposal (aswell as the necessary boat trips andassociated energy usage and airemissions) would be substantiallyreduced.

Response: EPA believes that it madea reasonable estimate of the quantity ofdrilling fluids and drill cuttings thatwould be required to be disposed ofonshore under the rule. EPA's estimateof the volume of drilling wastegenerated offshore is based on actualdischarge data and is demonstrative ofthe fairly high level of solids controlemployed offshore.

Solids control equipment is used bythe industry to remove drill cuttings andminimizelhe buildup of drilled solidsin the drilling fluid system. In additionto enhancing drilling fluid properties,by minimizing solids buildup in themud system the operator can reduce theextent to which dilution of the drillingfluid is required. All drilling operationsutilize solids control equipment to somedegree and the efficiency of the system,in determining the extent to whichdilution is required, affects the volumeof drilling wastes generated. A relativelylow efficiency (40 percent) solidscontrol system requires a substantiallevel of dilution in order to maintainproper mud system properties.Intermediate level of efficiency (about60 percent), in providing greater solidsremoval from the mud system,substantially reduces the level ofdilution required for the mud systemand reduces the volume of drillingwastes generated. The intermediatelevel system will result in an increasedvolume of drill cuttings and a decreasedvolume of drilling fluids. (While thetotal drilling waste volume is reducedbecause of the reduced dilution, aportion of drilled solids dischargedalong with drilling fluids in lowefficiency solids control systems will beremoved by the higher efficiency solidscontrol and included with the drillcuttings wastes.)

Finally, closed-loop solids controlsystems can provide approximately 80percent solids removal efficiency,further reducing the overall drillingwaste volume (the drill cuttings volumewould increase, but the drilling fluidvolume decreases by a greater amount.)While the closed-loop system providesvolume reductions over theintermediate-level system, thevolumetric reductions in wastegeneration are not linearly proportionalto the solids control efficiency. As aresult, operators gain significantlygreater reductions in drilling wastevolumes in going from low efficiency tointermediate level solids controlequipment than achieved in going from

intermediate-level equipment to closed-loop systems.

In developing the final rule, EPAconsidered solids control equipmentpractices used in the offshore oil andgas industry. In evaluating the potentialfor enhanced solids control systems toreduce drilling waste volumes (and thusreduce non-water quality environmentalimpacts), EPA reviewed industryliterature and solids control equipmentcurrently used in offshore drillingsituations and data on solid removalefficiencies. Based on the limited dataavailable, EPA has determined that theoffshore oil and gas Industry, while notusing the highest efficiency solidscontrol systems available, is in generalusing a fairly high level of solids controlin drilling operation.

While most platforms and drilling rigsmay have a basic level (relatively lowefficiency) of solids control equipmentpermanently installed, it is commonindustry practice for lease owners/operators, in contracting with theservice firms providing drilling services,to require sbme level of enhanced solidscontrol equipment to be used. EPA usedindustry data on drilling wastedischarges, (for which solidsinformation was unavailable) inconjunction with theoretical estimate ofdrilling waste volumes (calculated fromthe theoretical hole volume and use ofsolid control equipment with differingefficiencies), to determine that wastevolumes generated in the offshoresubcategory are demonstrative of a fairlyhigh solids control efficiency.

A factor to be considered in offshoreoperations is whether available spaceexists on the platform or mobile drillingrig to support installation of higherefficiency solids control equipment. Inonshore and coastal areas, drillingoperations typically are not severelylimited in terms of equipment space. (Incoastal regions, additional equipmentcan often be added on the drilling bargeor an additional barge brought to thedrilling site.) Offshore, however,operators must balance the benefits ofadding additional solids controlequipment with the need to reservespace on the platform or drilling rig forstorage of drill cuttings boxes. If theavailable space for storage of drillcuttings boxes becomes too limiting,additional boat trips to remove the drillcuttings are required if interruptions tothe drilling operation are to beprevented. Also, installing higher-efficiency solids control equipmentproduces a greater drill cuttings volume,further limiting drilling operations.(While the drilling fluid volume isdecreased, a corresponding spaceavailability does not result since the

muds are stored in tanks which have asmaller "footprint", or surface arearequirement. Operators are limited inthe extent to which cuttings boxes maybe stacked.) Operators may retrofitadditional platform space on platformsor mobile drilling rigs; however, insome cases such modifications may notbe feasible and in any case would bemade upon economic consideration ofmodification costs and onshore wastedisposal costs.

In evaluating the impact of enhancedsolids control equipment drilling wastevolumes requiring onshore disposal,EPA used its estimates of currentindustry practice, platform additioncosts, and onshore disposal costs toassess the potential for operators tofurther enhance their solids controlsystems. EPA was limited in thisanalysis by the lack of facility-specificdata regarding the installed solidscontrol equipment. Because the industryis already using a fairly high level ofsolids control (limiting the extent towhich benefits could be realizedthrough further efficiency increases),facility-specific data is lacking, andbecause the selection of the type ofsolids control system used at aparticular drilling location depends onsite-specific drilling conditions andeconomic variables, EPA was unable todetermine the extent to which theindustry would implement higher-efficiency solids control systems. To theextent that higher-efficiency solidscontrol equipment may be utilized,some reduction in the total drillingwaste volumes generated could berealized. Considering the fairly highlevel of efficiency already implementedoffshore, such volume reductions wouldnot likely be significant. Thus, EPAbelieves non-water qualityenvironmental impacts estimated fordrilling fluids and drill cuttings effluentlimitations and NSPS would not changesignificantly with implementation of

* higher-efficiency solids controlequipment.

Comment: EPA also receivedcomments opposed to the commentabove, that drilling waste volumes wereunderstated and that additional boattrips would be necessary.

Response: EPA reassessed drillingwaste volumes in developing the finalrule in response to public comments.The projected volumes of drilling fluidsand drill cuttings generated in theoffshore subcategory have changedslightly since proposal due to revisionsin calculations of: (1) The average welldepth, based on an expanded set ofdrilling data; (2) the typical depth of adeep well (deep wells generate greaterwaste volumes than shallow wells

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because of the footage drilled and thelarger diameter borehole used); and (3)the percentage of all wells drilledgreater than the average industryoffshore well depth. The methodologyused to calculate the drilling wastevolumes is unchanged from theproposal. In estimating the volume ofdrilling waste generated requiringonshore disposal, EPA reviseddownward projections of the usage ofoil-based drilling fluids. This downwardrevision reduces the volume of drillingwaste requiring onshore disposal.However, the decrease in onshoredisposal by this revision is offset by theupdated assumption of greater numbersof deep wells and the volume increaseassociated with these wells. For thesereasons, EPA believes that the projectedwaste volumes presented in section VUIof this preamble and the DevelopmentDocument are accurate estimates of thevolume of drilling fluids and drillcuttings requiring onshore disposal.

Comment: Some comentecontended that EPA's assumptionregarding the number of vesselsnecessary for transporting the drillingwastes was an over-estimate. Acommenter to the rule disputed EPA's1991 projections of the number ofsupply boats needed to transportdrilling wastes to shore. Thiscommenter claimed that EPAinappropriately estimated drilling wastevolumes, overestimated the number ofdedicated supply boats needed, andfailed to consider the potential for usingregularly scheduled supply boats tocarry drilling wastes to shore. Thecommenter claimed that the drillingwastes could be brought to shore byregularly scheduled supply boats andthat EPA was double-counting thenumber of boat trips needed.

EPA also received opposingcomments. One commenter claimed thatthere are no vessels (barges) configuredand certificated to carry oilfield wastesauthorized to operate in offshore waters,and noted the improbability ofmodifying the open hopper barge designoften used in inland wasters. Somecommenters contended that there wereinsufficient vessels available totransport the drilling wastes to shore.

Response: EPA strongly disagreeswith the contention that vessels areunavailable for offshore service. EPAestimates that approximately 760,000barrels per year of drilling wastes aretransported from drilling sites in theoffshore category to the shore fordisposal in order to comply with thecurrent BPT and NPDES permitlimitations. These wastes aretransported to shore by offshore servicevessels, typically supply boats. The

population of service vessels availableto transport offshore drilling wastes isdifficult to determine; however,estimates regarding the number ofvessels and the increased requirementsresulting from this rul can be made.

As discussed above, supply boatsmake frequent visits to drilling andproduction sites throughout the offshoresubcategory. Service vessel usage atoffshore facilities may be as high as twosupply boats per day and two crewboats per day during the explorationand development phases. In general,service vessels make three trips perweek to exploration and developmentoperations and one trip per week toproduction platforms. (EPA projectsfuture wells in the offshore subcategoryto be drilled at the average annual rateof about 760 wells per year. There arecurrently approximately 2,550production platforms in the offshoresubcategory.) MMS data show that therewere 25,000 service vessel trips tosupport oil and gas related activities onthe OCS (federal waters only) in theGulf of Mexico in 1988. These data donot differentiate between types ofvessels; however, it does provide someindication regarding the boat populationand level of activity. EPA estimates thattransporting drilling wastes to shore incompliance with the requirements ofthis rule will result in an increase ofabout 740 service vessel trips per year.(See the Development Document andrecord for this rule.)

EPA disagrees with the contentionthat the number of boats needed havebeen double-counted, and also does notagree that drilling wastes could bebrought to shore exclusively byregularly scheduled supply boats. Inprojecting the number of boat tripsrequired and associated non-waterquality environmental impacts, EPAdetermined that both dedicated andregularly scheduled supply boats will beused to transport drilling wastes toshore. In the early stages-of drilling awell, drill cuttings are generated at sucha rate and in sufficient quantity thatplatform storage space can be a limitingfactor and dedicated boats are needed tocollect the wastes and preventinterruptions to the drilling program. Aswaste generation rates decline (drillingrates decline and the well diameterbecomes smaller as depth increases),dedicated boats are unnecessary andregularly scheduled supply boats areused to transport the drilling wastes toshore. At the end of drilling, a dedicatedsupply boat is again typically needed toremove the bulk drilling fluid remainingin the system.

Comment: Some commenters statedthat there was insufficient onshore

disposal capacity available to receivedrilling wastes generated offshore.

Response: h this final rule, EPAupdated estimates of the onshoredisposal capacity for oilfield wastes.The onshore disposal capacity wasestimated on a regional basis indeveloping the November 1990 andMarch 1991 proposals. These regionalestimates were updated subsequent tothe proposal and identified currentpermitted capacity near the coast, thevolumes of oilfield wastes currentlytreated by those sites, and the "excess"disposal capacity available to acceptadditional waste volumes. Theprojections of onshore dispol capacityare discussed in more detail in sectionVII of this notice and the DevelopmentDocument. EPA concludes that there isadequate onshore disposal capacityavailable to accept offshore drillingwastes requiring onshore disposal underthis rule.E. Toxicity Limitation for Drilling Fluidsand Drill Cuttings

Comment: Numerous comments werereceived concerning the proposedtoxicity limitation for drilling fluids andcuttings. Some commenters argued thatthe limit was too stringent, while onecommenter argued that the limit was notstringent enough. Most of the commentsrelated to the original proposal in 1985to limit discharges of drilling fluids toonly those fluids that complied with atoxicity limitation for the suspendedparticulate phase (SPP) of 30,000 ppm(3 percent of volume). Drill cuttingsdischarges were to be controlled byprohibiting the discharge of free oil.Because of the adherence of drillingfluids to the cuttings during the drillingoperation, however, the toxicitylimitation for drill cuttings wasincluded in the 1991 proposaLCommenters to the 1991 proposal raisedthe same or similar issues eitherspecifically describing them in their1991 comments or by reference to their1985 comments. In general, industrycomments objected to the use of atoxicity limitation as being too stringent.Specifically, industry commenters saidEPA had not demonstrated a correlationbetween toxicity and the amount ofpollutants present in the drilling fluidswaste stream, had not verified withactual field data that the 30,000 ppm(SPP) limits can be achievedconsistently in actual drillingoperations, and had not demonstratedthat the limit can be met by drillingfluids which are necessary to drill safelyand effectively on the outer continentalshelf. Industry commenters also raisedissues concerning the toxicity testprotocol and the lack of quantified


Federal Register / Vol. 58,-No. 41 / Thursday, March 4, 1993 / Rules and Regulations

environmental benefits resulting fromimposition of the toxicity limitation.

On the other hand, one commenterstated that the 1991 proposed toxicitylimits of 30,000 ppm (SPP) were notstringent enough. The commenter statedthat the 30,000 ppm (SPP) limit on mudtoxicity is clearly not BAT and not evenBPT. This commenter also raisedquestions concerning use of a toxicitytest which does not take into accountsolid phase toxicity and chronictoxicity, including cumulative andsublethal effects. A toxicity limitation of100,000 ppm (SPP) instead of 30,000ppm (SPP) was recommended if EPA seta toxicity limit rather than establishinga zero discharge requirement. Thisrecommendation was based on a draftEnvironmental Assessment Report(1982) citing data summarizing 415toxicity tests of 68 muds using 70species from an unspecified number ofplatforms. Because 44 percent of thedata for the generic muds exhibitedtoxicity values greater than 100,000ppm (SPP), the commenterrecommended EPA raise the toxicitylimitation to a minimum toxicitylimitation of 100,000 ppm.

Response: Specific responses to theindividual comments related to the30,000 ppm (SPP) toxicity limitation arecontained in the response to commentsdocument for this final rule. A summaryof the major portions of these responsesis contained in this section of thepreamble. This summary describes thebasis for the 30,000 ppm (SPP)limitation, the appropriateness of theuse of this limitation for all drillingactivities and the suitability of thetoxicity test method. In addition, ananalysis of the economic impact of theselimitations is discussed further insection XIV of the Preamble, theEconomic Impact Analysis, and therecord for the rule. A summary ofcomments concerning theenvironmental benefits or lack thereof isnot contained in this section, but theindividual comments are addressed inthe comment response document andthe environmental assessmentconducted under Executive Order12291, which is described in section XVof this Preamble.

Compliance with the toxicitylimitation is based on the technologiesof (1) product substitution of lowertoxicity water-based or syntheticdrilling fluids for higher toxicity drillingfluids and (2) transport to shore forultimate land disposal of drilling wastes(fluids and cuttings) that do not meet

- the toxicity limits established by theseregulations. As required by the CWA,BAT limitations are to be based on thebest available technology and be

economically achievable. NSPS are toreflect the greatest degree of effluentreduction which the Administratordetermines to be achievable throughapplication of the best demonstratedcontrol technology, taking cost intoconsideration. Product substitution andtransport to shore if the drilling fluidsand drill cuttings to be disposed of willnot meet applicable effluent limitationsor NSPS, are the best available and bestdemonstrated technologies forcontrolling the discharge of toxic andnonconventional pollutants associatedwith the drilling fluids and drillcuttings wastestreams.

In response to industry comments thatthe limit is too stringent, EPA disagrees.EPA has determined that the toxicitylimitation meets the statutory criteria forBAT and NSPS. EPA believes that the30,000 ppm toxicity limit on drillingfluids is technologically achievablebecause industry has been operatingunder NPDES permits imposing such alimit since at least 1986 (General Permitfor the Outer Continental Shelf in theGulf of Mexico, 51 FR 24897). Asdiscussed further below, the eightgeneric drilling fluids have propertiesthat make them applicable to almost alldrilling situations. Also, as discussedbelow, where more toxic drilling fluidsare necessary, barging is available andadequate landfill disposal capacityexists to dispose of the drilling fluidsand drill cuttings on shore.

With respect to the comment that atoxicity limitation of 30,000 ppm (SPP)is too lenient, the commenter arguedthat the toxicity limit (based on the mosttoxic of eight drilling fluids) establishesa least common denominator, ratherthan the highest common denominatordemanded by the statutory definition ofBAT and NSPS. EPA disagrees.

In looking at how to apply a productsubstitution approach, EPA workedwith industry to identify water-basedgeneric drilling fluids that areapplicable to almost all drillingsituations. Drilling fluids are complexmixtures of chemical constituentsformulated to meet the individualrequirements of each well. Many of thechemicals have numerous functions inthe drilling fluids; however, individualchemicals usually have a primaryfunction. Important functions which areperformed by the drilling fluids are: theremoval of drilled solids (cuttings) fromthe bottom of the hole to the surfacewhere they are removed; the lubricationand cooling of the drill bit and string;the depositing of an impermeable layer(wall cake) on the well bore hole wallto seal the formation being drilled; thecontrol of downhole pressure; theholding of drill cuttings in suspension

within the fluid when circulation of thefluid is interrupted; the support of partof the weight of the drill bit and string;and the transmitting of hydraulichorsepower to the drill bit.

Drilling fluids are usually densecolloidal slurries which have severalphases (generally a water phase and asolid phase, some also have an oil phaseor a gas phase). The water phase mayrange from fresh to saturated saltmixtures. The fluids start with the waterphase and clay, either bentonite orattapulgite clay. All of the generic fluidsexcept one use one or the other of theseclays. The one fluid composition whichdoes not use either of these clays is thegeneric mud type #1, Seawater/Potassium/Polymer Mud. This mud usespotassium chloride starch and acellulose polymer. The use of thesecomponents in generic mud type #1 isnecessary because of the loose shaleconditions often encountered in theGulf of Mexico. The potassium chloridefunctions as a shale control additive, thecellulose polymer functions as a filtratereducer and shale controller and thestarch functions as a filtrate reducer.Both of these functions are important inkeeping fluids from the mud systemfrom entering the formation and keepingthe formation from collapsing into thehole.

The clays used in the drilling fluids(either bentonite or attapulgite) are veryhydrophilic and form the basis of aviscous gel. As drilling continues,drilled clays (from the formation) maythicken the drilling fluid, thus requiringthinners and dispersant to be added tocontrol flow or rheologicalcharacteristics of the fluid. Theserheological properties involve theviscosity and gel strength of the fluid,and are important in determiningfrictional pressure losses (lubricity), andthe ability of the fluid to lift cuttings tothe surface. A number of constituents(or additives) are used as dispersants orthinners, such as the lignosulfonates,lignite, phosphates and plant tannins.Several of the generic mud types usedin the toxicity limitation testingcontained these constituents (MudTypes #2, #3, #7, and #8).

Additional constituents must be usedin many drilling situations. Theseinclude barite, a weighting agent, whichcontrols downhole pressure by raisingthe density of the fluid system;bentonite, starch or other compounds,which control fluid loss by building afilter cake on the wall of the bore hole;and various constituents for lubricity,plugging holes in the formation whichcause loss of the entire drilling fluidslurry, and biocides to control bacterial

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growth which can interfere with thedrilling and/or production activity.

Commenters identified numerousexamples of the need for variouscompositions or types of fluids, genericor specialty, in order to drill in thedifferent formation characteristicsencountered in the Gulf of Mexico inparticular.

For example, if an ineffective shalestabilizer is-used, there could be severehole problems which would causeincreased drilling time and possible lossof the well; if the composition limits theamount of barite to that of the highestbarite content in any of the genericmuds, high pressure/high temperaturedrilling operations routinelyencountered in the Gulf of Mexico couldnot be conducted; and the use of KC1(potassium chloride) muds for watersensitive shale formation control,although sporadic, are essential.

Because EPA believes that drillingfluids exhibiting the characteristics ofthe eight generic fluids are necessary forindustry to conduct drilling operationsin almost all drilling situations, EPAneeded to set the compliance limitbased on the most toxic of these eightfluids. EPA recognizes that even withproduct substitution, with the limit setat 30,000 ppm (SPP), there will be someInstances in which the most toxic of thegeneric fluids or a more toxic drillingfluid or additive is needed to conductdrilling operations. The need foradditional lubricity, or the need tostabilize the well bore hole, particularlyin drilling through heavy shaleformations are examples of thesituations in which EPA believes theuse of constituents or additives mayrequire the drilling wastes to betransported to shore due to failure tocomply with the 30,000 ppm (SPP)toxicity limitation. Thus, in theseinstances, transporting the drillingfluids and drill cuttings to shore wouldbe the technology basis for compliancewith the limit instead of productsubstitution.

In response to the comments that the30,000 ppm (SPP) limitation is toolenient, EPA obtained the reportedtoxicity values of used drilling fluidsand cuttings from monitoring requiredby the Gulf of Mexico General Permit(Permit No. GM280000) and severalgeneral permits from Offshore Alaska(Permit Nos. AKG284100, AKG288000,AKG283000, and AKG785000). ThenEPA reviewed the distribution of thesedata. The available-data do not includethe level of information (describedbelow) necessary to determine if the lesstoxic drilling fluids used to result inlower effluent toxicity could be used toaddress the myriad of drilling situations

encountered in the field. Also, theprobability distribution of the resultsdoes not follow any of the commonlyused parametric distributions such asthe normal or lognormal distribution.Thus, EPA could not determine whetherthe less toxic results could be related tosome operational characteristics, norcould EPA extrapolate such arelationship based on these data.

Although the data show that drillingfluids and drill cuttings do have toxicityvalues higher (less toxic) than 30,000ppm (SPP), EPA cannot establish a morestringent limit based on this informationfor a number of reasons. First, the datarepresent the drilling fluids that havebeen discharged. Thus, while the dataindicate how frequently the .drillingfluid discharges meet the .30,000 ppm(SPP) limit, EPA does not have firminformation about the amount of drillingfluids and drill cuttings that are plannedto be barged to shore (not discharged)because the operator knows the 30,000ppm (SPP) toxicity limit cannot be met.Second, EPA does not know whatcomplete drilling fluid composition wasused in each case where we havetoxicity data. Thus, EPA does not knowwhether a particular fluid compositionthat gave lower toxicity results could beused in most drilling situations. Third,EPA does not have enough informationabout the specifics of the drillingsituation (meaning the formationgeology and what part of the drillingprocess was occurring) corresponding toeach toxicity data point. Thus, EPA doesnot know whether the particular fluidcompositions that gave lower toxicityresults represents the myriad of actualdrilling situations that occur in thefield. For these reasons, EPA isuncertain about why certain drillingfluids showed a toxicity less than30,000 ppm (SPP), but, unless EPA hasdata about the applicability of thosefluids to drilling needs across thesubcategory, EPA does not believe thata more stringent limit has been shownto be available technology for BATlimits or demonstrated availabletechnology for NSPS limits.

In response to the comment citingdata used in the EnvironmentalAssessment (1982), EPA does notbelieve that this data is useful forpurposes of establishing an effluentimitation. At the outset, the cited data

were used to demonstrate toxic effectsto aquatic organisms from discharges ofdrilling fluids and drill cuttings ratherthan to set an effluent limitation.Further, all of the same problemsdiscussed above regarding the use ofmonitoring data (e.g., not knowing whatfluid resulted in what effluent toxicity,what geological formation was being

drilled, and what phase of drilling wasoccurring) also applies to this data.Finally EPA cannot use this data tospecify a toxicity limit because it is notpossible to relate the data from manydifferent species to a single speciesbioassay upon which the 30,000 ppmSPP limit is based.

The toxicity limitation is analogous toa daily maximum limitation requiredunder this and other effluent guidelines.Such limitations include an allowancefor reasonable treatment systemvariability that provides for variation inoperating conditions expected at well-operated facilities. Operationally,ninety-ninth percentile estimates,determined through statistical analysesof performance data, are used as thebasis for daily maximum limitations.The Agency believes that suchlimitations provide sufficient allowancefor variation in normal operations.While the permit monitoring data arenot the same type of data typically usedto develop effluent guidelines (becausewe do not know what drilling fluid wasused, what type of geology wasencountered, and what part of thedrilling process was occurring, amongother things, see discussion above), thepercentage of toxicity data that are moretoxic than the 30,000 ppm (SPP) limit isapproximately one percent no matterhow the combined data from the Gulf ofMexico and Alaska Regions areanalyzed. Thus, a review of these datashows that the 30,000 ppm (SPP)toxicity limit based on a productsubstitution approach is similar to theapproach EPA generally takes inestablishing maximum daily limitations.

In addition, EPA has considered that,in the absence of a reliable estimate ofthe number of facilities that couldcomply with a more stringent limitation,there would be an unknown amount ofdrilling fluids and drill cuttings notmeeting the limitation that would needto be transported to shore.

In Alaska, transport to shore on aregular basis is not technologicallyachievable because of the specialclimate conditions that make transportfrom platforms to shore and groundtransportation on shore infeasibleduring extended periods of time; inaddition there is a lack of available landdisposal sites. For these reasons, EPAexcluded Alaska from the zero-discharge requirement applicable todrilling fluids and drill cuttings withinthree miles from shore.

In other regions, such a limit wouldincrease the amount of non-waterquality environmental impacts inaddition to those already imposed bythe three-mile zero dischargerequirement for drilling fluids and drill



cuttings. Any increase in the toxicitylimit would have an unknown increasein the amount of air emissions andenergy use from transporting drillingfluids and drill cuttings to shore, and anincrease in the amount of drilling fluidsand drill cuttings that would need to bedisposed of in land disposal sites.

In short, because EPA does not havesufficient information to know if a morestringent toxicity limit would be feasiblefor drilling needs across the subcategoryand because EPA does not know whateffect a more stringent toxicity limitwould have on non-water qualityenvironmental impacts, in the final rule,EPA is setting the toxicity limit at30,000 ppm (SPP), a level which EPAknows to be feasible without interferingunreasonably with drilling operationsand which does not result inunacceptable non-water qualityenvironmental impacts.

Industry comments have asserted thatthe EPA toxicity test is not suitable forcompliance monitoring of an effluentguideline. These comments are notcorrect. The toxicity test for drillingfluids is suitable because the testdemonstratively measures the acutetoxicity for the drilling fluid andmultiple tests on the same toxicsubstance show a spread of toxicityvalues about an average toxicity value.One term for the spread of valuesaround the average toxicity value isvariability. Variability for this test isestimatedin Variability Study of theEPA Toxicity Test for Drilling Fluids:Statistical Analysis (1993). Given thatthere are variability issues associatedwith any measurement test, theseproperties of the toxicity test areallowed for in setting the effluentguidelines limitation by using the EPAtoxicity test to measure the toxicity ofsamples from a model "system" of eightgeneric drilling fluids. Since precisionand accuracy are inherent componentsof the toxicity test and are thereforeinherent in the data that result from thetest, these factors are entrained in thesubsequent calculations performed todevelop effluent limitations from thosedata. That adequate variability wasallowed for in this procedure isdemonstrated by the high percentage,greater than 90 percent of offshore wellsin the Gulf of Mexico that compliedwith this limitation as a permitrequirement in the years 1984 to 1991.

EPA also notes that the 30,000 ppmSPP toxicity limit has been imposed asa requirement in the general permits forthe Outer Continental Shelf (OSC) in theGulf of Mexico since 1986. This limitwas upheld in NRDC v. EPA, 863 F.2d1420 (9th Cir. '1988). A pre-approvalsystem based on this limit was imposed

in two general permits for the Beringand Beaufort Seas in 1984 and wasupheld in APIv. EPA, 787 F.2d 965 (5thCir. 1986).

F. Static Sheen TestComment: Several areas addressed by

the comments received on the staticsheen test concerned the difficulty andexpense of conducting the test, thereproducibility and accuracy of the test,and the need for such a test from theenvironmental benefits perspective.Commenters stated that the test methodwas not well established nor costeffective and results in inaccurateidentifications of sheens, both falsepositives and negatives (i.e., when no

ee oil is present but is identified andwhen oil is present but not identified,respectively). In addition, commenterscriticized the Agency for not quantifyingthe benefits of the test method, whileothers supported the method as being"scientifically superior" to the visualsheen method previously used, becauseunlike the static sheen test, the visualsheen test is used to detect violationsafter discharge.

Response: EPA disagrees with thecomment that the static sheen test is notwell established, expensive and notcost-effective. The static sheen test,described in appendix I of the finalrule, is the test method used todetermine compliance with the no freeoil requirement, except for the no freeoil requirement for deck drainage. Thevisual sheen test is retained to measuredeck drainage compliance.

The static sheen test differs from thevisual sheen test by utilizing samples ofthe wastes to be tested (15 milliliter or15 gram (on a wet weight basis) quantitydepending on the type of waste)introduced into a container (bucket)filled with seawater and having aspecified surface area, rather thanvisually looking at the surface of thereceiving water for the occurrence of asheen after discharge of the waste. In thestatic sheen test, observations are madeno more than one hour after the wastesamples are added to and dispersedupon the container of seawater.

EPA believes that the static sheen testis both established and inexpensive toconduct. The test method contained inthe final rule is based on the methodproposed in 1985 (50 FR 34627) and hasbeen modified to reflect the methodused in the Region 10 general permits.Possible changes to the 1985 proposedmethod were noticed in the 1991proposal (56 FR 10675), including theRegion 10 method. The Region 10protocol was selected based on resultsof assessments that demonstrate lowerfalse positives (56 FR 10676) and its use

over a ten year period with acceptablereproducibility. This protocolincorporates a larger waste sample andcontainer of seawater and uses a moredetailed description of criteria fordetermining whether a sheen exists ornot, than the 1985 version of the test.EPA believes this is an improvementover the 1985 version; however, EPAcontinues to believe that the 1985version of the test method demonstratesacceptable accuracy.

In response to comments concerningthe benefits of the test, EPA believesthat a test method that evaluates thepotential of a sheen prior to the wastebeing discharged more effectively meetsthe intent of the CWA. The static sheentest also eliminates or reduces effects ofwave action, weather conditions, andlighting (sunlight or lack of lighting)which the use of the visual sheen on thereceiving waters must overcome. WhileEPA is not required to assess theenvironmepntal benefits of a test method,EPA notes that because the static sheentest can be used in advance of dischargeto determine noncompliance, it ispreferable from an environmentalstandpoint to a test (like the visualsheen test) that determinesnoncompliance only after dischargeoccurs.

G. Effluent Guidelines Resulting in a"Taking"

Comment: One commenter arguedthat EPA should assess the takingsimplications of these effluent guidelinespursuant to Executive Order 12630.Another commenter argued that theseeffluent guidelines limitations couldresult in a "taking."

Response: EPA-believes that takingsclaims do not apply to effluentlimitations guidelines because the issuearises only when the guidelines areapplied to a particular property. In achallenge to EPA's regulations of theplacer mining industry, a federal courtof appeals found that a takings claimwas not ripe because the guideline hadnot yet been applied to a particularproperty. Rybachek v. U.S. EPA, 904F.2d 1276 (9th Cir. 1990).XVII. Best Management Practices

Section 304(e) of the CWA authorizesthe Administrator to prescribe "bestmanagement practices" (BMP's). EPA isnot promulgating BMP's for the offshoresubcategory at this time.

XVIII. Upset and Bypass ProvisionsA recurring issue of concern has been

whether industry guidelines shouldinclude provisions authorizingnoncompliance with effluent limitationsduring periods of "upsets" or

12501



"bypasses". An upset, sometimes calledan "excursion," is an unintentionalnoncompliance occurring for reasonsbeyond the reasonable control of thepermittee. It has been argued that anup set provision Is necessary in EPA'seffluent limitations because such upsetswill inevitably occur even in properlyoperated control equipment. Becausetechnology based limitations requireonly what the technology can achieve,it is claimed that liability for suchsituations is improper. When confrontedwith this issue, courts have disagreed onwhether an explicit upset exemption isnecessary, or whether upset Incidentsmay be handled through EPA's exerciseof enforcement discretion. CompareMarathon Oil Co. v. EPA, 564 F.2d 1253(9th Cir.1977), with Weyerhaeuser v.Costle, 594 F.2d 1223 (8th Cir. 1979).See also Sierra Club v. Union Oil Co.,813 F.2d 1480 (9th Cir. 1987), AmericanPetroleum Institute v. EPA, 540 F.2d1023 (10th Cir. 1976), CPCInternational, Inc. v. Train, 540 F.2d1320 (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.

EPA has determine that both upsetand bypass provisions should beincluded in NPDES permits and haspromulgated permit regulations thatinclude upset and bypass permitprovisions. See 40 CFR 122.41. Theupset provision establishes an upset asan affirmative defense to prosecution forviolation of, among other requirements,technology-based effluent limitations.The bypass provision authorizesbypassing to prevent loss of life,personal injury, or severe propertydamage. Consequently, althoughpermittees in the offshore oil and gasindustry will be entitled to upset andbypass provisions in NPDES permits,this regulation does not address theseissues.

XIX. Variances and ModificationsOnce this regulation is in effect, the

effluent limitations must be applied inall NPDES permits thereafter issued todischarges covered under this effluentlimitations guideline subcategory.Under the CWA certain variances fromBAT and BCT limitations are providedfor. Variances such as 301(c) (EconomicAchievability from BAT) and 301(g)(variance from BAT for specific listednon-conventional pollutants) are notapplicable to BAT and BCT limitationspromulgated in this rule because thereare no such limitations in this rule. A

section 301(n) (Fundamentally DifferentFactors) variance is applicable to theBAT and BCT limits in this rule.

The Fundamentally Different Factors(FDF) variance considers those facilityspecific factors which a permittee mayconsider to be uniquely different fromthose considered in the formulation ofan effluent guideline as to make thelimitations inapplicable. An FDFvariance must be based only oninformation submitted to EPA duringthe rulemaking establishing the effluentlimitations from which the variance isbeing requested, or on information theapplicant did not have a reasonableopportunity to submit during therulemaking process for these effluentlimitations guidelines. If fundamentallydifferent factors are determined, by thepermitting authority (or EPA). to exist,

Ahe alternative effluent limitations forthe petitioner must be no less stringentthan those justified by the fundamentaldifference from those facilitiesconsidered in the formulation of thespecific effluent limitations guideline ofconcern. The alternative effluentlimitation, if deemed appropriate, mustnot result in non-water qualityenvironmental impacts significantlygreater than those accepted by EPA inthe promulgation of the effluentlimitations guideline. FDF variancerequests with all supporting informationand data must be received by thepermitting authority within 180 days ofpublication of the final effluentlimitations guideline [Publication datehere]. The specific regulations coveringthe requirements for and theadministration of FDF variances arefound at 40 CFR 122.21(m)(1), and 40CFR part 125, subpart D.

XX. Implementation of Limitations andStandards

A. Toxicity Limitation for Drilling Fluidsand Drill Cuttings

The toxicity limitation would apply toany periodic blowdown of drilling fluidas well as to bulk discharges of drillingfluids and drill cuttings systems. Theterm "drilling fluid systems" refers tomuds and additives used during thedrilling of an individual exploration,.development or production well. Anygiven well may require several types ofmud due to changes in downholeconditions. As an example, a well mayrequire use of a spud mud for the first200 feet, a seawater-gel mud to a depthof 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 spent.drilling fluids occur when mud systems

are changed during drilling of or uponcompletion of a well.

For the purpose of self monitoringand reporting requirements in NPDESpermits, it is intended that only samplesof the discharged drilling fluid systemsbe analyzed in accordance with thebioassay method. Upon (or before)discharge a mud system should besampled by bioassay to determinetoxicity of the discharge. All dischargedmuds should be analyzed. Muds that arenot discharged (i.e., reinjected ordisposed onshore) are not subject to thetoxicity limit. In the example above,four such samples and bioassays wouldbe required because four discrete mudsystems are being discharged.

For determining the toxicity of thebulk discharge of mud used atmaximum well depth, samples may beobtained at any time after 80% of actualwell footage (not total vertical depth)has been drilled to the end of well (100percent vertical depth) and up to andincluding the time of discharge. Permitwriters have the discretion to specifythe appropriate point of the well depthwithin these parameters at which theend of well sample will be obtained.This would allow time for a sample tobe collected and analyzed by bioassayand for the operator to evaluate thebioassay results so that the operator willhave adequate time to plan for the finaldisposition of the spent drilling fluidsystem, e.g., if the bioassay test is failed,the operator could then anticipate andplan for transport of the spent drillingfluid system to shore in order to complywith the effluent limitation. However,the operator is not precluded fromdischarging a spent mud system prior toreceiving analytical results.Nonetheless, the operator would besubject to compliance with the effluentlimitations regardless of when selfmonitoring analyses are performed. Theprohibition on discharges of free oil anddiesel oil would apply to all dischargesof drilling fluid at any time.

B. Diesel Prohibition for Drilling Fluidsand Drill Cuttings

Diesel oil is prohibited from dischargefrom offshore oil platforms. In additionto this prohibition, drilling fluids anddrill cuttings that produce a sheen orfail the toxicity limitations cannot bedischarged. There is, however, thepossibility that the quantity of diesel oilin the drilling fluid or drill cuttings isinsufficient to produce a sheen ortoxicity at a level failing the limitations.Thus, to show compliance with thediesel oil discharge prohibition, theoperator is required to prove that dieseloil is not present in the dischargematerial. This requirement has created



the need for measurement of "dieseloil".

As part of this rulemaking, EPA hasdeveloped an analytical techniquecapable of measuring diesel oil indrilling wastes and that woulddistinguish diesel oil from mineral oil,crude oil, and/or the additives that arealso used in drilling fluids. Althoughmany different techniques have beentested, there is no single analyticaltechnique capable of unambiguouslymeasuring diesel oil in drilling mud. Inthe March 13, 1991 proposal notice (56FR 10676), EPA identified the EPAMethod 1651 as adequate for use inidentifying the presence of diesel oil.However, work was continued onalternative extraction and analysistechniques to simplify the operationalportions of the method and enable betteridentification of diesel oil in thepresence of interferences. As a result,EPA has developed test methods for themeasurement of the hydrocarbonsnormally found in oil, including thepolynuclear aromatic hydrocarbon(PAH) content of the oil. Combined,these techniques can be used to discerndiesel oil In the presence of othercomponents likely to be found in

'drilling wastes. This section gives abrief history of the efforts to develop testmethods for the determination of dieseloil in drilling fluids and drill cuttingsand a description of test methods thathave been developed to measure anddifferentiate diesel oil, mineral oil, andcrude oil.

In late 1990, the American PetroleumInstitute (API) undertook a study ofextraction and determination stepsnecessary to identify unambiguouslydiesel oil in the presence ofinterferences, and to overcomedifficulties using Method 1651. Thesestudies involved the evaluation ofalternate extraction and determinationtechniques.

Extraction techniques includedultrasonic, Soxhlet/Dean-Stark, andsupercritical fluid. Determinativetechniques included high performanceliquid chromatography with ultra-violetdetection (HPLC/UV), and gaschromatography with flame ionizationdetection (GC/FID). One devicecombined extraction and determination.In this device, the drilling waste samplewas placed in a small chamber andheated rapidly to desorb the oil into aflowing gas stream. The components ofoil entrained in the gas stream wereseparated by gas chromatography, anddetection by flame ionization.

Of these devices, Soxhlet/Dean-Starkextraction provided the most preciseresults and the results closest to truevalue, and HPLC/UV was found reliable

for determining polynuclear aromatichydrocarbons (PAHs) in the extract.Results of these studies are summarizedin an April 1992 API Report, entitled,"Results of the API Study of Extractionand Analysis Procedures for theDetermination of Diesel Oil in DrillingMuds" (the API Report). A copy of theAPI Report is included in the record forthe rulemaking.

Based on the additional methodswork resulting from comments on theproposed Method 1651, EPA ispromulgating, in addition to the Method1651, a test protocol measuring the PAHcontent by HPLC/UV to demonstratethat the oil is mineral oil, and will allowmeasurement of the normalhydrocarbon distribution by GC/FID todembnstrate that the oil is crude oil.However, EPA will not allow use of thetotal oil content to demonstrate that themud is free of diesel oil.

EPA recognizes that in certain regionscompliance with the diesel oilprohibition is accomplished by GCanalysis of end.of-well samples. In otherregions, compliance with the dieselprohibition is accomplished by reviewof well records maintained by platformoperators to prove that diesel oil has notbeen added to the mud system. Bothmethods of determining compliance areacceptable. However, in the latter casewhere the enforcement agency believesthat the well record is in error or hasbeen falsified, the authority may insistthat further testing be conducted toprove that diesel oil has not been used.

In this further testing for the presenceof diesel oil, the drilling fluid or drillcuttings are extracted with a solvent andthe amount of total extractable materialis measured. If the material extractedexceeds the amount attributable toadditives, the material could be dieseloil, crude oil, or mineral oil, and thenext phase of testing must beconducted..

In this next phase, the PAH content ofthe oil in the drilling waste isdetermined using the HPLC/UVMethod. If the PAH content is less thanthat attributable to mineral oil, the mudmay be discharged; if greater tift thatattributable to mineral oil, the oil couldbe either diesel or crude oil. Todetermine whether the oil is diesel orcrude, the absence of n-alkanes in thediesel range or the percent of C25-C30alkanes using the GC/FID Method mustbe used to show that the oil was crudeoil from the formation. If the oil wascrude oil, the mud may be dischargedproviding it meets the other dischargelimitations of the rule. Implementationof this approach employs methodscontained within "Methods for theDetermination of Diesel, Mineral, and

Crude Oils in Offshore Oil and GasIndustry Discharges" (EPA 821-R-92-008).

XXI. Availability of TechnicalInformation

The basis for this regulation isdetailed in three major documents eachof which in turn is supported andsupplemented by additional informationand analyses in the rulemaking record.EPA's technical foundation for theregulation is detailed in the"Development Document for FinalEffluent Limitations Guidelines andNew Source Performance Standards forthe Offshore Subcategory of the Oil andGas Extraction Point Source Category"(EPA/821-R-93-003) EPA's economicanalysis is presented in the "EconomicImpact Analysis of Effluent LimitationsGuidelines and Standards ofPerformance for the Offshore Oil andGas Industry" (EPA/821-R-93-004)EPA's analysis of the monetized benefitsof the regulation are presented in the"Regulatory Impact Analysis of theEffluent Guidelines Regulation forOffshore Oil and Gas Facilities" (EPA/821-R-93-002). Detailed responses tothe public comments received on theproposed regulation and notices of dataavailability are presented in thedocument entitled "Response to PublicComments on Effluent LimitationsGuidelines and New SourcePerformance Standards for the OffshoreSubcategory of the Oil and GasExtraction Point Source Category."Additional information concerning theeconomic impact analysis andregulatory impact analysis may beobtained from Dr. Mahesh Podar,Engineering and Analysis Division(WH-552), U.S. EnvironmentalProtection Agency, 401 M Street, SW.,Washington, DC 20460 or by calling(202) 260-5387. Technical informationmay be obtained from Mr. Ronald P.Jordan, Engineering and AnalysisDivision (WH-552), at the aboveaddress, or by calling (202) 260-7115.The public record for this rulemaking isavailable for review at EPA's WaterDocket; 401 M Street, SW.; Washington,DC.

XXII. Office of Management and Budget(OMB) Review

This regulation and the RegulatoryImpact Analysis were submitted to theOffice of Management and Budget(OMB) for review as required byExecutive Order 12291. The regulationdoes not contain any informationcollection requirements.

12503



List of Subjects in 40 CFR Part 435Incorporation by reference, Oil and

gas exploration, Oil and gas extraction,Waste treatment and disposal, Waterpollution control.

Dated: January 15, 1993.William K. Reilly,Administrator.

Appendix to the Preamble

Appendix A-Abbreviations, Acronyms, andOther Terms Used in this Final RuleDocument

Act-Clean Water ActAgency-US. Environmental Protection

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

economically achievable, under section304(b)2)(B) of the Clean Water Act.

bbl-barrel, 42 U.S. gallons.bpd--arrels per day.BCT-Best conventional pollutant control

technology under section 3041b)(4)(B).BMP-Best management practices under. section 304(e) of the Clean Water Act.

BOD-Biochemnical oxygen demand.BPT-Best practicable control technology

currently available, under section 404(b)(1)of the Clean Water Act.

Bypass-An act of intentionalnoncompliance during which wastetreatment facilities are circumventedbecause of an emergency situation.

CFR--Code of Federal Regulations.Clean Water Act-Federal Water Pollution

Control Act Amendments of 1972 (33U.S.C. 1251 et seg.), as amended by theClean Water Act of 1977 (Pub. L 95-217).

CWA--Cean Water Act.Direct discharger-A facility which

discharges or may discharge pollutants towaters of the United States.

DOE-Department of Energy.DOE/EIA-Department of Energy, Energy

Information Administration.EIA-Economic Impact Analysis.EPA-U.S. Environmental Protection

Agency.g-gram.GOM--GuIf of Mexico.kg--kilogram.LC50-The concentration of a test material

that is lethal to 50% of the test organismsin a bloassay.

mg/i-milligrams per liter.MMS-Minerals Management Service, U.S.

Department of the Interior.NORM-Naturally Occurring Radioactive

Materials.NPDES Permit-A National Pollutant

Discharge Elimination System permitissued under section 402 of the CleanWater Act

NRDC--Natural Resources Defense Council.NSPS-New source performance standards

under section 306 of the Clean Water Act.OCS--Outer Continental Shelf.OOC-Offshore Operators Committee.POTW-Publicly Owned Treatment Works.ppm-parts per million.Priority Pollutants-The 65 pollutants and

classes of pollutants declared toxic undersection 307(a) of the Clean Water Act.

RCRA--Resource Conservation and RecoveryAct of 1976 (42 U.S.C. sections 6901-6992k). Amendments to Solid WasteDisposal Act.

SPP-Suspended particulate phase.Spot-The introduction of oil to a drilling

fluid system for the purpose of freeing astuck drill bit or string.

Upset-An unintentional noncomplianceoccurring for reasons beyond thereasonable control of the permittee.

U.S.C.-United States Code.USCG-U.S. Coast Guard.

For the reasons set out in thepreamble, 40 CFR part 435 is amendedas set forth below:

PART 435-ONL AND GASEXTRACTION POINT SOURCECATEGORY

1. The authority citation for part 435is revised to read as follows:

Authority: 33 U.S.C. 1311,1314, 1316,1317, 1318 and 1361.

2. 40 CFR part 435, subpart A isrevised to reed as follows:

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 I to Subpart A of Part 435-StaticSheen Test

Appendix 2 to Subpart A of Part 435--Drilling Fluids Texicity Test

Subpart A-Offshore Subcategory

§ 435.It App cability; description of theoffshore subcategory.

The provisions of this subpart areapplicable to those facilities engaged infield exploration, drilling, wellproduction, and well treatment in theoil and gas extraction industry whichare located in waters that are seaward ofthe inner boundary of the territorial seas("offshore") as defined in section 502(g)of the Clean Water Act. Offshorefacilities that transport wastes toonshore or coastal locations fortreatment and disposal offshore aresubject to the regulations that are

applicable to the location of where thewastes are generated or the wellhead.Wastes transported from onesubcategory for subsequent discharge inanother subcategory of the oil and gasextraction point source category mayonly be disposed of pursuant to a validNPDES permit.

5435.11 Specialized definitions.For the purpose of this subpart: (a)

Except as provided in paragraphs (b)through (aa) of this section, the generaldefinitions, abbreviations and methodsof analysis set forth in 40 CFR Part 401shall apply to this subpart.

b)The term average of daily valuesfor 30 consecutive days shall be theaverage of the daily values obtainedduring any 30 consecutive day period.

(c) The term daily values as appliedto produced water effluent limitationsand NSPS shall refer to the dailymeasurements used to assesscompliance with the maximum for anyone day.

(d) The term deck drainage shall referto any waste resulting from deckwashings, spillage, rainwater, andrunoff from gutters and drains includingdrip pans and work areas withinfacilities subject to this subpert.

(e) The term development facilityshall mean any fixed or mobile structuresubject to this subpart that is engaged inthe drilling of productive wells.

(f) The term diesel oil shall refer to thegrade of distillate fuel oil, as specifiedin the American Society for Testing andMaterials Standard Specification D975-81, that is typically used as thecontinuous phase in conventional oil-based drilling fluids. This incorporationby reference was approved by theDirector of the Federal Register inaccordance with 5 U.S.C. 552(a) and 1CFR part 51. Copies may be obtainedfrom the American Society for Testingand Materials, 1916 Race Street,Philadelphia, PA 19103. Copies may beinspected at the C)ffice of the FederalRegister, 800 North Capitol Street, NW.,suite 700, Washington, DC.

(g) The term domestic waste shallrefer to materials discharged from sinks,showers, laundries, safety showers, eye-wash stations, hand-wash stations, fishcleaning stations, and galleys locatedwithin facilities subject to this subpart.

(h) The term drill cuttings shall referto the particles generated by drillinginto subsurface geologic formations andcarried to the surface with the drillingfluid.

(i) The term drilling fluid shall referto the circulating fluid (mud) used inthe rotary drilling of wells to clean andcondition the hole and tocounterbalance formation pressure. A



water-based drilling fluid is theconventional drilling mud in whichwater is the continuous phase and thesuspending medium for solids, whetheror not oil is present. An oil-baseddrilling fluid has diesel oil, mineral oil,or some other oil as its continuousphase with water as the dispersedphase.

(j) The term exploratory facility shallmean any fixed or mobile structuresubject to this subpart that is engaged inthe drilling of wells to determine thenature of potential hydrocarbonreservoirs.

(k) The term maximum as applied toBAT effluent limitations and NSPS fordrilling fluids and drill cuttings shallmean the maximum concentrationallowed as measured in any singlesample of the barite.

(1) The term maximum for any oneday as applied to BPT, BCT and BATeffluent limitations and NSPS for oiland grease in produced water shallmean the maximum concentration.allowed as measured by the average offour grab samples collected over a 24-hour period that are analyzedseparately. Alternatively, for BAT andNSPS the maximum concentrationallowed may be determined on the basisof physical composition of the four grabsamples prior to a single analysis.

(m) The term minimum as applied toBAT effluent limitations and NSPS fordrilling fluids and drill cuttings shallmean the minimum 96-hour LC50 valueallowed as measured in any singlesample of the discharged waste stream.The term minimum as applied to BPTand BCT effluent limitations and NSPSfor sanitary wastes shall mean theminimum concentration value allowedas measured in any single sample of thedischarged waste stream.

(n) The term M9IM shall mean thoseoffshore facilities continuously mannedby nine (9) or fewer persons or onlyintermittently manned by any numberof persons.

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

(p)(1) The term new source means anyfacility or activity of this subcategorythat meets the definition of "newsource" under 40 CFR 122.2 and meetsthe criteria for determination of newsources under 40 CFR 122.29(b) appliedconsistently with all of the followingdefinitions:

(i) The term water area as used in theterm "site" in 40 CFR 122.29 and 122.2shall mean the water area and oceanfloor beneath any exploratory,development, or production facilitywhere such facility is conducting its

exploratory, development or productionactivities.

(ii) The term significant sitepreparation work as used in 40 CFR122.29 shall mean the process ofsurveying, clearing or preparing an areaof the ocean floor for the purpose of"constructing or placing a developmentor production facility on or over the site.

(2) "New Source" does not includefacilities covered by an existing NPDESpermit immediately prior to theeffective date of these guidelinespending EPA issuance of a new sourceNPDES permit.

(q) The term no discharge of free oilshall mean that waste streams may notbe discharged when they would cause afilm or sheen upon or a discoloration ofthe surface of the receiving water or failthe static sheen test defined inAppendix 1 to 40 CFR 435, subpart A.

(r) The term produced sand shall referto slurried particles used in hydraulicfracturing, the accumulated formationsands and scales particles generatedduring production. Produced sand alsoincludes desander discharge from theproduced water waste stream, andblowdown of the water phase from the,produced water treating system.

(s) 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.

(t) The term production facility shallmean any fixed or mobile structuresubject to this subpart that is eitherengaged in well completion or used foractive recovery of hydrocarbons fromproducing formations.

(u) The term sanitary waste shall referto human body waste discharged from.toilets and urinals located withinfacilities subject to this subpart.

(v) The term static sheen test shallrefer to the standard test procedure thathas been developed for this industrialsubcategory for the purpose ofdemonstrating compliance with therequirement of no discharge of free oil.The methodology for performing thestatic sheen test is presented inAppendix 1 to 40 CFR 435, subpart A.

(w) The term toxicity as applied toBAT effluent limitations and NSPS fordrilling fluids and drill cuttings shallrefer to the bioassay test procedurepresented in Appendix 2 of 40 CFR 435,subpart A.

(x) The term well completion fluidsshall refer to salt solutions, weightedbrines, polymers, and various additivesused to prevent damage to the well boreduring operations which prepare the

drilled well for hydrocarbonproduction.

(y) The term well treatment fluidsshall refer to any fluid used to restoreor improve productivity by chemicallyor physically altering hydrocarbon-bearing strata after a well has beendrilled.

(z) The term workover fluids shallrefer to salt solutions, weighted brines,polymers, or other specialty additivesused in a producing well to allow formaintenance, repair or abandonmentprocedures.

(aa) The term 96-hour LC50 shall referto the concentration (parts per million)or percent of the suspended particulatephase (SPP) from a sample that is lethalto 50 percent of the test organismsexposed to that concentration of the SPPafter 96 hours of constant exposure.

§435.12 Effluent limitations guidelinesrepresenting the degree of effluentreduction attainable by the application ofthe best practicable control technologycurrently available (MPT).

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 practicablecontrol technology currently available:

BPT EFFLUENT LiMITATIONS-OIL ANDGREASE

tin milligrams per ierl

Averageof values Residual

Pollutant parameter Maximum for 30 chlorinew for any 1 consecu- minimumwaste source day tive days for any 1

shall not dayexceed

Produced water ..... 72 48 NADeck drainage (1) (1) NADrlling muds ......... (1) ( NADrill cuttings .......... () () NAWell treatment

fluids .................. () () NASanitary:

M1O ................... NA NA 21

M9lM 3 ............... NA NA NADomestic ............... NA NA NA

INo discharge of free oil.Minimum of 1 mgl and maintained as close to

this concentration as possible.3There shall be no floailng solids as a result of thedischarge of these wastes,

§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 available

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12506 Federal Register / Vol. 58, No. 41 / Thursday, March 4, 1993 / Rules and Regulationsteholg eooicly cieal

technology economically achievable(BAT):

BAT EFFLUENT LIMITATIONS

Waste source Pollutant BAT effluent im-parameter Itation

Produced water .... Oi & The maximumgrease. for any one

day shall notexceed 42mgl the aver-age of dailyvalues for 30consecutivedays shall notexceed 29n A.

Drilling fluids anddrill cuttings:

(A) For facilities to- .................... No discharge.'cated within 3Miles from shoe.

(B) For lacilities o- Toxicity ..... inimum 96-cated beyond 3 hour LC50 ofMks km shore. the SPP Shall

be 3% by vol-ume. 2

Fre ol ...... No discharge.3

Dieee o .... NO disch3argMercury 1 mgtkg dry

weigt mal-mum In thestock berile.

Cadmium. 3 mgg dryweight max-mum In thestock barite.

Wel tirament, ON and The maximumcompletion, and grease. for any onewouicover flulds. day shall not

exceed 42mg/I; the aver-ago of dailyvelues for 30consecutivedays shall notexceed 29Mg&

Deck drainage __ Free on ..... NO discharge. 4

Produced sand .................... No discharge.Domestic Waste ... Foam ..... No discharge.

'All Alaskan faciities are subject to the drilingfluids and orill cuttings discharge limitations forfacilities located beyond 3 miles offshore.2As determined by the toxicity test (Appendix 2).3As determined by the static sheen test (Appendix1).

4 As determined by the presence of a film or sheenupon or a discoloration of the surface of the receivingwater (visual sheen).

§435.14 Effluent limitations guidelinesrepresenting the degree of effluentreduction attainable by the application ofthe beet 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):

. BCT Effluent Limitations

Pollutant BCT efluent n-Waste source parameter itatlon

Produced water .... Ol & The maximumgrease, for any one

day awa notexceed 72mgl; the aver-age of valuesfor 30 con-secIve daysshall not ex-ceed48 mg.


(A) For facilities lo- ......... No dicharge.1cated within 3miles from shore.

(B) For facilities lo- Free oi ..... No discharge.2

cated beyond 3miles from shore.

Wail treatment, Free oil .... No discharge.2

completion andworkover fluids.

Deck drainage ...... Free ol ...... No discharge.3Prducaed sand ...................... No discharge.San"tay MO ....... Residual Minmum of 1

chorne. mgf andmaintained ascose to thisconcentrationas possible.

Sanitary M91M ..... Floating sol- No discharge.ids.

Domesic Waste ... Floating aol- No discharge.

AN other do- See 33 CFRmastic Part 151.waste.

'A Alaskan faclitles are subject to the drillingfluids and dill cuttings discharge limitations forfacilities located more than 3 meles offshore.2As determined by te static sheen tes (A(pendik

3 As determined by the presence of a finm or sheenupon or a discoloration o the surace of 1he receivingwater (visual sheen).

§435.15 Standards of performance fornew sources (NSPS).

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

NEW SOURCE PERFORMANCE STANDARDS

Waste source Poltant NSPSIparameter

Produced water ...


(A) For facilitieslocated wlhin 3miles fromshore.

(B) For facilitieslocated morethan 3 milesfrom shore.

ol andgrease.

Toxicity ......

Free o.Diesel oll

The maximum forany one dayshall not ex-ced 42 rg/&;the average ofdaily values for30 consecutive

NEW SOURCE PERFORMANCESTANDARDS--ConInued

Waste soue Polant NSPSWastesoume parameter

Mercury ..... I mfkg drywegh maximum In thestock batle.

Cadmium ... 3 mg/kg dryweight maxi-mum in ie"stock barlis.

Well treatment Oil nd The maximum forcompletion, and grease. any one dayworkover fluids. shall not ex-

ceed 42 mgthe average ofdaly v lues for30 consecutivedays ihall notexceed 29 mgfI.

Deck drainage ..... Free oil No isharge.'Produced sand .......... ......... No discharge.SariitaryM10 ....... Residual MInmum o I

chlorka mg and main-lained as closeto this as pos-sible.

Sanitary M91M ..... Floating sol- No discharge.ids.

Domestic Wasie.. Flo ig lao- NO disrge.Ida.

Foam ......... No discharge.AN other do- See 33 CFR Part

mastic 151.wastes.

IAN Alaskan lacilitles are subJect to the dtllngfluids and drill cutlings diacnarge standards orfacilities located more than three miles offshore.2 As determined by the toxiy test (Appendix 2).

3AS deterimned by ft static sheen tes (Appendix1)4 As determined by the presence of a fim or sheen

upon or a discoloratlon of the swtace of Iti receiwngwater (viuial sheen).

Appendix I to Subpart A of Part 435-Static Sheen Test

1. Scope and Application

This method is to be used as acompliance test for the "no discharge offree oil" requirement for discharges ofdrilling fluids, drill cuttings, producedsand, and well treatment, completionand workover fluids. "Free oil" refers toany oil contained in a waste stream thatwhen discharged will cause a film orsheen upon or a discoloration of thesurfacie of the receiving water.

2. Summary of Method

days shall not 15-mL samples of drilling fluids orexceed 29 mg/ well treatment, completion, andL workover fluids, and 15-g samples (wet

weight basis) of drill cuttings orNo discharge., produced sand are introduced into

ambient seawater in a container havingan air-to-liquid interface area of 1000

Minimum 9e-hour cm 2 (155.5 in2). Samples are dispersedLCS0 of te within the container and observationsSPP sall be 3 made no more than one hour later topercent by v1* ascertain if these materials cause a

No discharge.1 sheen, iridescence, gloss, or increasedNo discharge, reflectance on the surface of the test



seawater. The occurrence of any of thesevisual observations will constitute ademonstration that the tested materialcontains "free oil," and therefore resultsin a prohibition of its discharge intoreceiving waters.

3. Interferences

Residual "free oil" adhering to samplingcontainers, the magnetic stirring bar used tomix the sample, and the stainless steelspatula used to mix the sample 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 forsimilar contamination from pipettes and thetest container.

4. Apparatus, Materials, and Reagents4.1 Apparatus

4.1.1 Sampling Containers: 1-literpolyethylene beakers and 1-liter glassbeakers.

4.1.2 Graduated cylinder: 100-mLgraduated 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 pipettes: 25-mL

disposable pipettes.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 of1000 cm 2±50 cm2 (155.5 ±7.75 in2). anda depth of at least 13 cm (5 inches) andno more than 30 cm (11.8 inches).

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

Oil-free, heavy-duty plastic trash canliners that do not inhibit the spreadingof an oil film. Liners must be ofsufficient size to completely cover theinterior surface of the test container.Permittees must determine anappropriate local source of liners that donot inhibit the spreading of 0.05 mL ofdiesel fuel added to the lined testcontainer under the test conditions andprotocol described below.

4.2.2 ' Ambient receiving water.

5. CalibrationNone currently specified.

6. Quality Control ProceduresNone currently specified.

7. Sample Collection and Handling7.1 Sampling containers must be

thoroughly washed with detergent, rinsed aminimum of three times with fresh water,and allowed to air dry before samples arecollected.

7.2 Samples of drilling fluid to be testedshall be taken at the shale shaker aftercuttings have been removed. The samplevolume should range between 200 mL and500 mL

7.3 Samples of drill cuttings will be takenfrom the shale shaker screens with a cleanspatula or similar instrument and placed in

a glass beaker. Cuttings samples shall becollected prior to the addition of anywashdown water and should range between200 g and 500 g.

7.4 Samples of produced sand must beobtained from the solids control equipmentfrom which the discharge occurs on anygiven day and shall be collected prior to theaddition of any washdown water; samplesshould range between 200 g and 500 g.

7.5 Samples of well treatment,completion, a d workover fluids must beobtained from the holding facility prior todischarge; the sample volume should rangebetween 200 mL and 500 mL.

7.6 Samples must be tested no later than1 hour after collection.

7.7 Drilling fluid samples must be mixedin their sampling containers for 5 minutesprior to the test using a magnetic bar stirrer.If predilution is Imposed as a permitcondition, the sample must be mixed at thesame ratio with the same prediluting wateras the discharged muds and stirred for 5minutes.

7.8 Drill cuttings must be stirred and wellmixed by hand in their sampling containersprior to testing, using a stainless steelspatula.

8. Procedure

8.1 Ambient receiving water must beused as the "receiving water" in the test. Thetemperature of the test water shall be as closeas practicable to the ambient conditions inthe receiving water, not the roomtemperature of the observation facility. Thetest container must have an air-to-liquidinterface area of 1000 ±50 cm 2. The surfaceof the water should be no more than 1.27 cm(.5 inch) below the top of the test container.

8.2 Plastic liners shall be used, one pertest container, 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 A 15-mL sample of drilling fluid orwell treatment, completion, and workoverfluids must be introduced by pipette into thetest container I cm below the water surface.Pipettes must be filled and discharged withtest material prior to the transfer of testmaterial and its introduction into testcontainers. The test water/test materialmixture must be stirred i-,ing the pipette todistribute the test material homogeneouslythroughout the test water. The pipette mustbe used only once for a test and thendiscarded.

8.4 Drill cuttings or produced sandshould be weighed on plastic weighing boats;15-g samples must be transferred by scrapingtest material into the test water with astainless steel spatula. Drill cuttings shall notbe prediluted prior to testing. Also, drilling'fluids and cuttings will be tested separately.The weighing boat must be immersed in thetest water and scraped with the spatula totransfer any residual material to the testcontainer. The drill cuttings or producedsand must be stirred with the spatula to aneven distribution of solids on the bottom ofthe test container."8.5 Observations must be made no laterthan 1 hour after the test material is

transferred 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. It is recommended that the watersurface of the test container be observedunder a fluorescent light source such as adissecting microscope light. The light sourceshall be positioned above and directed overthe entire surface of the pan.

8.6 Detection of a "silvery" or "metallic"sheen or gloss, increased reflectivity, visualcolor, Iridescence, or an oil slick on the watersurface of the test container surface shallconstitute a demonstration of "free oil."These visual observations include patches,streaks, or sheets of such altered surfacecharacteristics. If the free oil content of thesample approaches or exceeds 10%, thewater surface of the test container may lackcolor, a sheen, dr iridescence, due to theincreased thickness of the film; thus, theobservation for an oil slick is required. Thesurface of the test container shall not bedisturbed in any manner that reduces the sizeof any sheen or slick that may be present

If an oil sheen or slick occurs on less thanone-half of the surface area after the sampleis introduced to the test container,observations will continue for up to I hour.If the sheen or slick increases in size andcovers greater than one-half of the surfacearea of the test container during theobservation period, the discharge of thematerial shall cease. If the sheen or slick doesnot increase in size to cover greater than one-half of the test container surface area afterone hour of observation, discharge maycontinue and additional sampling is notrequired.

If a sheen or slick occurs on greater thanone-half of the surface area of the testcontainer after the test material is introduced,discharge of the tested material shall cease.The permittee may retest the material causingthe sheen or slick. If subsequent tests do notresult in a sheen or slick covering greaterthan one-half of the surface area of the testcontainer, discharge may continue.Appendix 2 to Subpart A of Part 435-Drilling Fluids Toxicity Test

I. Sample CollectionThe collection and preservation methods

for 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 for

water and drilling mud sampling and storage:a. Acid-rinsed linear-polyethylene bottles

or 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.

12507



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

I-B. Water Sampling(1) Collection of water samples shall be

made with appropriate acid-rinsed linear-polyethylene bottles or other appropriatenon-contaminating water sampling devices.Special care shall be taken to avoid theintroduction of contaminants from thesampling devices and containers. Prior touse, the sampling devices and containersshould be thoroughly cleaned with adetergent solution, rinsed with tap water,soaked in 10 percent hydrochloric acid (HCI)for 4 hours, and then thoroughly rinsed withglass-distilled water.

I-C. Drilling Mud Sampling(1) Drilling mud formulations to be tested

shall be collected from active field systems.Obtain a well-mixed sample from beneath theshale shaker after the mud has passedthrough the screens. Samples shall be storedin polyethylene containers or in otherappropriate 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 0-40 C until the time of testing.

(3) Bulk mud samples shall be thoroughlymixed in the laboratory using a 1000 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 under pressure anytime thecontainers are opened. Moreover, the samplein any container opened for testing must bethoroughly stirred using a 1000 rpm highshear mixer prior to use.

(5) Most drilling mud samples may bestored for periods of time longer than 2weeks prior to toxicity testing provided thatproper containers are used and propercondition are maintained.

IL 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.

II--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 I Lc. Large (15 cm) powder funnels.d. Several 2-liter graduated cylinders.e. Several 2-liter large mouth graduated

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

thoroughly 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 bath

for 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: If the glassware with nytex cupssoaks in the acid solution longer than 24hours, then an equally long deionized watersoak should be performed.

I-B Test Seawater Sample Preparation(1) Diluent seawater and exposure seawater

samples are prepared by filtration through a1.0 micrometer filter prior to analysis.

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

II-C Sample Preparation(1) The pH of the mud shall be tested prior

to its use. If the pH is less than 9, if blackspots have appeared on the walls of thesample container, or if the mud sample hasa foul odor, that sample shall be discarded.Subsample a manageable aliquot of mud fromthe well-mixed original sample. Mix the mudand filtered test seawater in a volumetricmud-to-water ratio of I to 9. This is best doneby the method of volumetric displacement ina 2-L, large mouth, graduated Erlenmeyerflask. Place 1000 mL of seawater into thegraduated Erlenmeyer flask. The mudsubsample is then carefully added via apowder funnel to obtain a total volume of1200 mL. (A 200 mL volume of the mud willnow be in the flask).

The 2-L, large mouth, graduatedErlenmeyer flask is then filled to the 2000 mLmark with 800 mL of seawater, whichproduces a slurry with a final ratio of onevolume drilling mud to nine volumes water.If the volume of SPP required for testing oranalysis exceeds 1500 to 1600 mL, the initialvolumes should be proportionatelyincreased. Alternatively, several 2-L drillmud/water slurries may be prepared asoutlined above and combined to providesufficient SPP.

(2) Mix this mud/water slurry withmagnetic stirrers for 5 minutes. Measure thepH and, if necessary, adjust (decrease) the pHof the slurry to within 0.2 units of theseawater by adding 6N HCI while stirring theslurry. Then, allow the slurry to settle for 1hour. Record the amount of HC1 added.

(3) At the end of the settling period,carefully decant (do not siphon) theSuspended Particulate Phase (SPP) into anappropriate container. Decanting the SPP isone continuous action. In some cases no clearinterface will be present; that is, there willbe 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, thesample must be remixed for five minutes.This insures the homogeneity of the mixtureprior to the preparation of the testconcentrations. In other cases, there will besamples with two or more phases, including

a solid phase. For those samples, carefullyand continuously decant the supernatantuntil the solid phase on the bottom of theflask is reached. The decanted solution isdefined to be 100 percent SPP. Any otherconcentration of SPP refers to a percentage ofSPP that is obtained by volumetricallymixing 100 percent SPP with seawater.

(4) SPP samples to be used in toxicity testsshall be mixed for 5 minutes and must notbe preserved 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 is65 percent 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 to 7.8±.1 units.Record the amount of acid oi NaOH neededto lower/raise to the appropriate pH. Threerepeated DO and pH measurements areneeded to insure homogeneity and stabilityof the 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 Day0. Then, the animals shall be randomlyselected and placed in the dishes in order tobegin the 96-hour toxicity test.

I1. Guidance for Performing SuspendedParticulate Phase Toxicity Tests UsingMysidopsis bahia

Il1-A Apparatus(1) Items listed by Borthwick [1] are

required for each test series, which consistsof one set of control and test containers, withthree replicates of each.

III-B Sample Collection Preservation(1) Drilling muds and water samples are

collected and stored, and the suspendedparticulate phase prepared as described inSection 1-C.

Ill-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 beas gentle as possible. Transportation to thelaboratory should be in well-aerated waterfrom the animal culture site at thetemperature and salinity from which theywere cultured. Methods for handling,acclimating, and sizing bioassay organismsgiven by Borthwick I1] and Nimmo 121 shallbe followed in matters for which no guidanceis given here.

III-D Experimental Conditions(1) Suspended particulate phase (SPP) tests

should be conducted at a salinity of 20±2 ppt.Experimental temperature should be 20±2°C.


Federal Register / Vol. 58, No. 41 / Thursday, March 4, 1993 / Rules and Regulations 12509

Dissolved oxygen in the SPP shall be raisedto or maintained above 65 percent ofsaturation prior to preparation of the testconcentrations. Under these conditions oftemperature and salinity, 65 percentsaturation 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 par liter.

(2) Aeration of test media is requiredduring the entire test with a rate estimatedto be 50-140 cubic centimeters/minute. Thisair flow to each test dish may be achievedthrough polyethylene tubing (0.045-inchinner diameter and 0.062-inch outerdiameter) by a small generic aquarium pump.The delivery method, surface area of theaeration stone, and flow characteristics shallbe documented. All treatments, includingcontrol, shall be the same.

(3) Light intensity shall be 1200microwatts/cm 2 using cool white fluorescentbulbs with a 14-hr light and 10-hr dark cycle.This light/dark cycle shall also be maintainedduring the acclimation period and the test.

III-E Experimental Procedure(1) Wash all glassware with detergent, rinse

five times with tap water, rinse once withacetone, rinse several times with distilled ordeionized water, place in a clean 10 percentHCI acid beth for a minimum of 4 hours,rinse five times with tap water, and thenrinse five times with distilled water.

(2) Establish the definitive testconcentration based on results of a rangefinding test. A minimum of five testconcentrations plus a negative and positive(reference toxicant) control is required for thedefinitive test. To estimate the LC-50, twoconcentrations shall be chosen that give(other than zero and 100 percent) mortalityabove 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" nytex holdingcups are fabricated 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 then placed into the testconcentration within the confines of theNytex cups.

(4) Individual organisms shall be randomlyassigned to treatment. A randomizationprocedure is presented in Section V of thisprotocol. Make every attempt to exposeanimals of approximately equal size. Thetechnique described by Borthwick (1l, orother suitable substitutes, should be used fortransferring specimens. Throughout the testperiod, mysids shall be fed daily withapproximately 50 Artemia (brine shrimp)nauplii per mysid. This will reduce stressand decrease cannibalism.

(5) Cover the dishes, aerate, and incubatethe test containers in an appropriate testchamber. Positioning of the test containersholding 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 pHmeasurements 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. Methods for Positive Control Tests(Reference Toxicant)

(1) Sodium lauryl sulfate (dodecyl sodiumsulfate) is used as a reference toxicant for thepositive control. The chemical used should

be approximately 95 percent pure. Thesource, lot number, and percent purity shallbe reported.

(2) Test methods are those used for thedrilling fluid tests, except that the testmaterial was prepared by weighing one gramsodium lauryl sulfate on an analyticalbalance, adding the chemical to a 100-milliliter volumetric flask, and bringing theflask to volume with delonized 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 test setup, as specified in therandomization procedure, consists of 3replicates of 20 animals for-each of the sixtreatments, i.e., 360 animals per test. FigureI is a flow diagram that depicts theprocedure schematically and should bereviewed to understand the over-alloperation. The following tasks shall beperformed in the order listed.

(2) Mysids are cultured in the laboratory inappropriate units. If mysids are purchased,go to 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 testingr will berequired to successfully complete these tests.SLUNG CODE o65o-6"



Figure 1Mysid Randomization Procedure

Mysids Are Collected3 To 6 Days Prior

To Testing

1 Culture Units L

2 MaintenanceContainer(s)

Test PopulationContainer(s)

Separation/4 Enumeration

Containers

Counting Dish5 (repeat tasks 5-7

for Al & A2 containers)

6 DistributionContainers

7 TestContainers

BLING CoC VO-W-p



(4) Remove mysids from maintenancecontainers and place all animals in a singlecontainer. The intent is to have homogeneoustest population of mysids of a known 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 containers. Transfer themysids from the large test populationcontainer to the labeled separation andenumeration containers but do not placemore than 200 mysids in a 500-mL beaker.Be impartial in transferring the mysids; placeapproximately equal numbers of animals(10-15 mysids Is convenient) in eachcontainer in a cyclic manner rather thanplacing the maximum number each containerat one time.

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 large volume containers withaeration. The idea is to provide the animalswith near optimal conditions 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 Carolinadishes 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, twoor more 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 36Individually numbered distributioncontainers (10-ml beakers are suggested). Themysids are assigned two at a time to 'the 36containers by using a randomizationschedule similar to the one presented below.At the end of selection/assignment round 1,each container will contain two mysids; atthe end of round 2, they will contain fourmysids; and so on until each contains tenmysids.

EXAMPLE OF A RANDOMIZATION SCHEDULE

Place mysid In theSelectionassignment round numberel istrbution

(2 mysids each) contamews In the ran-dom order shown

1 ......................................... 8,21,8,28,33,32,1,3, 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 36distribution containers to 18 labeled testcontainers in random order. A label isassigned to each of the three replicates (A, B,C) of the six test concentrations. Count andrecord the 96 hour response in an impartialorder.

(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 is conducted,the procedures described above areappropriate and should be used to preparethe single test concentration and control,along with the reference toxicant test.

V-B. Data Analysis and Interpretation(1) Complete survival data in all test

containers at each observation time shall bepresented in tabular form. If greater than 10percent mortality occurs in the controls, alldata shall be discarded and the experimentrepeated. Unacceptably high controlmortality indicates the presence of importantstresses on the organisms other than thematerial being tested, such as injury ordisease, stressful physical or chemicalconditions in the containers, or improperhandling, acclimation, or feeding. If 10percent mortality or less occurs in thecontrols, the data may be evaluated andreported.

(2) A definitive, full bioassay 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 mortalityor natural 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 usingthe logarithmic transform of theconcentration. The heterogeneity factor(Finney 1971, pages 70-72) is not used. Fora test material to pass the toxicity test,according to the requirements stated in theoffshore oil and gas extraction industry BATeffluent limitations and NSPS, the LC-50,adjusted for natural responsiveness, must begreater than 3 percent suspended particulatephase (SPP) concentration by volumeunadjusted for the I to 9 dilution. Othertoxicity test models may be used to obtaintoxicity estimates provided the modeledmathematical expression for the lethality ratemust increase continuously withconcentration. The lethality rate Is modeledto increase with concentration to reflect anassumed increase in toxicity withconcentration even though the observedlethality may not increase uniformly becauseof the 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 assay maybe too coarse to establish an adequate set oftest concentrations for a definitive test.

(4) The EPA Environmental ResearchLaboratory in Gulf Breeze, Florida prepareda Research and Development Report entitledAcute Toxicity of Eight Drilling Fluids toMysid Shrimp (Mysidopsis bahia), May 1984EPA-600/3,-84-067. The Gulf Breeze data fordrilling fluid number I are displayed inTable I for purposes of an example of theprobit analysis described above. The SASProbit Procedure (SAS Institute, StatisticalAnalysis System, Cary, North Carolina, 1982)was used to analyze these data. The 96-hourLC50 adjusted for the estimated spontaneousmortality rate is 3.3 percent SPP with 95percent limits of 3.0 and 3.5 percent SPPwith the I to9 dilution. The estimatedspontaneous mortality rate based on all of thedata is 9.6 percent.

TABLE 1.-USTING OF ACUTE TOXICITYTEST DATA (AUGUST 1983 TO SEPTEM-BER 1983) wiTH EIGHT GENERIC DRILL-ING FLUIDS AND MYSID SHRIMP

[fluid N2=11

Percent concentra- Number Number Numbertcon Number dead (96 alive (96tio exose hours). hours)

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

12511



V-C. The Partial Toxicity Test for Evaluationof Test Material

(I) 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 LG-50 adjted 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) concentration in the column labeled Xoof Table 2. If the number of organisms 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 is

less than or equal to corresponding numberin the column labeled X, then the testmaterial passes the partial toxicity test.Otherwise the test material fials the toxicitytest.

(4) Data shall be reported as percentsuspended particulate phase.

TABLE 2

Xo X1

0 ...................... ..... 22

S... ..... o..... ..................... 222 ............ ................. 23

3 .. ............. 234 .................................................... 245 . .. . ........... .............................. 24

6 ........... ...................................... 25

V7. References1. Borthwick. Patrick W. 1978. Methods for

acute static toxicity tests with mysid shrimp(Mysidopsis bahia). Bioassay Procedures forthe Ocean Disposal Permit Program, [EPA-600/9-78-010:1 March.

2. Nimmo, D.R., T.L Hamaker. and C.A.Somers. 1978. Culturing the mysid(Mysidopsis bahia) in flowing seawater or astatic system. Bioassay Procedures for theOcean Disposal Permit Program, (EPA-600/9-78-010): March.

3. American Public iealth Association etal. 1980. Standard Methods for theExamination of Water and Wastewater.Washington, D.C. 15th Edition: 90-99.

4. U.S. Environmental Protection Agency,September 1991. Methods for Measuring theAcute Toxicity of Effluents and ReceivingWaters to Freshwater and Marine OrganismsEPA/600/4-901027. Washington, D.C. 4thEdition.

5. Finney, D.J. Probit Analysis. CambridgeUniversity Press; 1971.

6. U.S. Environmental Protection Agency,May 1984. Acute Toxicity of Eight DrillingFluids to Mysid Shrimp (Mysidopsis bahia).EPA-60013-84-067.[FR Doc. 93-4528 Filed i-3-93, 8:45 amlELUNG CODE 8565


Documents

Granular Filtration Capital and Annual 3. ADDRESSES: For 4....cadmium and mercury at 3 mg/kg and I mg/kg, respectively, in stock barite (on a dry weight basis); (3) prohibit the discharge