EPA Waste Discharge Limits

6850 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

ENVIRONMENTAL PROTECTIONAGENCY

40 CFR Parts 9 and 435

[FRL–6929–8]

RIN 2040–AD14

Effluent Limitations Guidelines andNew Source Performance Standardsfor the Oil and Gas Extraction PointSource Category; OMB ApprovalUnder the Paperwork Reduction Act:Technical Amendment

AGENCY: Environmental ProtectionAgency (EPA).ACTION: Final Rule; technicalamendment.

SUMMARY: EPA is publishing finalregulations establishing technology-based effluent limitations guidelinesand standards for the discharge ofsynthetic-based drilling fluids (SBFs)and other non-aqueous drilling fluidsfrom oil and gas drilling operations intowaters of the United States. Oil and gasextraction facilities generate cuttingswastes from drilling operations. Thisregulation applies to existing and newsources that perform oil and natural gasextraction drilling in certain offshoreand coastal waters. The final rule allowsa controlled discharge of SBF-cuttingsanywhere offshore of Alaska andoffshore of the rest of the United Statesbeyond three miles from shore. This

regulation prohibits discharge of suchfluids in coastal Cook Inlet, Alaska,unless certain findings are made by thepermit authority. The final ruleprohibits the discharge of SBFs notassociated with drill cuttings into allwaters of the United States.

Compliance with this rule isestimated to reduce the annualdischarge of cuttings by 118 millionpounds per year for new and existingsources. This rule will also lead to adecrease of 2,927 tons of air emissionsand 200,817 barrels of oil equivalent(BOE) per year for new and existingsources. EPA estimates that the rule willresult in annual savings of $48.9 millionand no adverse economic impacts to theindustry as a whole. EPA alsoincorporated Best Management Practices(BMPs) into the final rule to provideindustry with additional flexibility inmeeting today’s final rule. Incompliance with the PaperworkReduction Act (PRA), this action alsomakes a technical amendment to thetable in part 9 that lists the Office ofManagement and Budget (OMB) controlnumbers issued under the PRA fortoday’s final rule. EPA is amending part9 to include the OMB control numberfor the information collectionrequirements associated with the BMPspromulgated in today’s final rule.DATES: This regulation shall becomeeffective February 21, 2001. For judicialreview purposes, this final rule is

promulgated as of 1 p.m. Eastern Timeon February 5, 2001, as provided in 40CFR 23.2. The incorporation byreference of certain publications listedin the regulations is approved by theDirector of the Office of Federal Registeras of February 21, 2001.ADDRESSES: The public record isavailable for review in the EPA WaterDocket, East Tower Basement, RoomEB–57, 401 M St. SW., Washington, DC20460. The public record for this rulehas been established under docketnumber W–98–26, and includessupporting documentation, but does notinclude any information claimed asConfidential Business Information (CBI).The record is available for inspectionfrom 9 a.m. to 4 p.m., Monday throughFriday, excluding legal holidays. Foraccess to docket materials, please call(202) 260–3027 to schedule anappointment.

FOR FURTHER INFORMATION CONTACT: Foradditional technical information contactMr. Carey A. Johnston at (202) 260–7186or send E-mail to:[email protected]. For additionaleconomic information contact Mr. JamesCovington at (202) 260–5132 or send E-mail to: [email protected] INFORMATION:

Regulated Entities

Entities potentially regulated by thisaction include:

Category Examples of regulated entities

Industry ................................. Facilities engaged in the drilling of wells in the oil and gas industry in areas defined as ‘‘coastal’’ or ‘‘offshore’’and discharging in geographic areas where drilling wastes are allowed for discharge (anywhere offshore ofAlaska and offshore of the rest of the United States beyond three miles from shore, and the coastal waters ofCook Inlet, Alaska). Includes certain facilities covered under Standard Industrial Classification code 13 andNorth American Industrial Classification System codes 211111 and 213111.

This table is not intended to beexhaustive, but rather provides a guidefor readers regarding entities likely to beregulated by this action. This table liststhe types of entities that EPA is nowaware could potentially be regulated bythis action. Other types of entities notlisted in the table could also beregulated. To determine whether yourfacility is regulated by this action, youshould carefully examine theapplicability criteria in 40 CFR part 435(see §§ 435.10 and 435.40). If you havequestions regarding the applicability ofthis action to a particular entity, consultthe person listed for technicalinformation in the preceding FORFURTHER INFORMATION CONTACT section.

Compliance Dates

Deadlines for compliance with BestPracticable Control TechnologyCurrently Available (BPT), BestConventional Pollutant ControlTechnology (BCT), and Best AvailableTechnology Economically Achievable(BAT) are established in NationalPollutant Discharge Elimination System(NPDES) permits. A new source mustcomply with New Source PerformanceStandards (NSPS) on the date the newsource commences discharging.

Technical Amendments to Part 9

EPA is amending the table ofcurrently approved informationcollection request (ICR) control numbersissued by OMB for various regulations.The amendment updates the table to listthose information collection

requirements promulgated undertoday’s final rule. The affectedregulations are codified at 40 CFR part9. EPA will continue to present OMBcontrol numbers in a consolidated tableformat to be codified in 40 CFR part 9of the Agency’s regulations, and in eachCFR volume containing EPAregulations. The table lists CFR citationswith reporting, recordkeeping, or otherinformation collection requirements,and the current OMB control numbers.This listing of the OMB control numbersand their subsequent codification in theCFR satisfies the requirements of thePaperwork Reduction Act (44 U.S.C.3501 et seq.) and OMB’s implementingregulations at 5 CFR part 1320.

This ICR was previously subject topublic notice and comment prior toOMB approval. Due to the technical

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6851Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

nature of the table, EPA finds thatfurther notice and comment isunnecessary. As a result, EPA finds thatthere is ‘‘good cause’’ under section553(b)(B) of the AdministrativeProcedure Act, 5 U.S.C. 553(b)(B), toamend this table without prior noticeand comment. As a result of today’stechnical amendment pertaining toBMPs, EPA is now authorized under thePaperwork Reduction Act to conduct orsponsor the information collectionrequirements in 40 CFR 435.13, 435.15,435.43, and 435.45.

Supporting Documentation

The rules promulgated today aresupported by several major documents:

1. ‘‘Economic Analysis of FinalEffluent Limitations Guidelines andStandards for Synthetic-Based DrillingFluids and other Non-Aqueous DrillingFluids in the Oil and Gas ExtractionPoint Source Category’’ (EPA–821–B–00–012). Hereafter referred to as the SBFEconomic Analysis, this documentpresents the analysis of compliancecosts and/or savings; facility closures;and changes in rate of return. Inaddition, impacts on employment andaffected communities, foreign trade,specific demographic groups, and newsources also are considered.

2. ‘‘Development Document for FinalEffluent Limitations Guidelines andStandards for Synthetic-Based DrillingFluids and other Non-Aqueous DrillingFluids in the Oil and Gas ExtractionPoint Source Category’’ (EPA–821–B–00–013). Hereafter referred to as the SBFDevelopment Document, the documentpresents EPA’s technical conclusionsconcerning the promulgated rules. Thisdocument describes, among otherthings, the data collection activities, thewastewater treatment technologyoptions, effluent characterization,effluent reduction of the wastewatertreatment technology options, estimateof costs to the industry, and estimate ofeffects on non-water qualityenvironmental impacts.

3. ‘‘Environmental Assessment ofFinal Effluent Limitations Guidelinesand Standards for Synthetic-BasedDrilling Fluids and other Non-AqueousDrilling Fluids in the Oil and GasExtraction Point Source Category’’(EPA–821–B–00–014). Hereafter referredto as the SBF EnvironmentalAssessment, the document presents theanalysis of water quality impacts foreach regulatory option. EPA describesthe environmental characteristics of SBFdrilling wastes, types of anticipatedimpacts, and pollutant modeling resultsfor water column concentrations, porewater concentrations, and human health

effects via consumption of affectedseafood.

4. ‘‘Statistical Analyses SupportingFinal Effluent Limitations Guidelinesand Standards for Synthetic-BasedDrilling Fluids and other Non-AqueousDrilling Fluids in the Oil and GasExtraction Point Source Category’’(EPA–821–B–00–015). Hereafter referredto as the SBF Statistical SupportDocument, this document presentsanalyses of retention on cuttings of SBF.EPA describes the performancecharacteristics of cuttings treatmenttechnologies and calculates summarystatistics for use as numerical limits.

How To Obtain Supporting Documents

All documents are available from theNational Service Center forEnvironmental Publications, PO Box42419, Cincinnati, OH 45242–2419,(800) 490–9198. The supportingtechnical documentation (e.g., SBFDevelopment Document) and previoustechnical documentation and FederalRegister notices can also be obtained onthe Internet, located atWWW.EPA.GOV/OST/GUIDE. Thiswebsite also links to an electronicversion of today’s final rule.

Overview

This preamble includes a descriptionof the legal authority for these finalregulations; a summary of the finalregulations; background information onthe industry and its processes; adescription of the technical andeconomic methodologies and data usedby EPA to develop these regulations;and a summary of EPA responses tomajor comments received on theProposal (February 3, 1999; 64 FR 5488)and Notice of Data Availability (April21, 2000; 65 FR 21548). The definitions,acronyms, and abbreviations used inthis preamble are defined in AppendixA.

Organization of This Document

I. Legal AuthorityII. Background

A. Clean Water ActB. Pollution Prevention ActC. Profile of IndustryD. Proposed RuleE. Notice of Data Availability

III. Summary of Data and InformationReceived in Response to the Notice ofData Availability

A. Pollutant Loading and Numeric LimitAnalyses

B. Compliance Costs AnalysesC. Economic Impacts AnalysesD. Water Quality Impact and Human

Health AnalysesE. Non-Water Quality Environmental

Impact AnalysesF. Compliance Analytical Methods

IV. Summary of Revisions Based on Notice ofData Availability Comments

A. Pollutant Loading AnalysesB. Compliance Costs AnalysesC. Economic Impacts AnalysesD. Water Quality Impact and Human

Health AnalysesE. Non-Water Quality Environmental

Impact AnalysesF. Numerical Limits for Retention of SBF

Base Fluid on SBF-cuttingsV. Development and Selection of Effluent

Limitations Guidelines and StandardsA. Waste Generation and CharacterizationB. Selection of Pollutant ParametersC. Regulatory Options Considered and

Selected for Drilling Fluid NotAssociated with Drill Cuttings

D. BPT Technology Options Consideredand Selected for Drilling FluidAssociated with Drill Cuttings

E. BCT Technology Options Consideredand Selected for Drilling FluidAssociated with Drill Cuttings

F. BAT Technology Options Consideredand Selected for Drilling FluidAssociated with Drill Cuttings

G. NSPS Technology Options Consideredand Selected for Drilling FluidAssociated with Drill Cuttings

H. PSES and PSNS Technology OptionsI. Best Management Practices (BMPs) to

Demonstrate Compliance with NumericBAT Limitations and NSPS for DrillingFluid Associated with Drill Cuttings

VI. Costs and Pollutant Reductions for FinalRegulation

A. Compliance CostsB. Pollutant Reductions

VII. Economic Impacts of Final RegulationA. Impacts AnalysisB. Small Business Analysis

VIII. Water Quality and Non-Water QualityEnvironmental Impacts of FinalRegulation

A. Overview of Water Quality and Non-Water Quality Environmental Impacts

B. Water Quality ModelingC. Human Health Effects ModelingD. Seabed SurveysE. Energy ImpactsF. Air Emission ImpactsG. Air Emissions Monetized Human Health

BenefitsH. Solid Waste ImpactsI. Other Factors

IX. Regulatory RequirementsA. Executive Order 12866: Regulatory

Planning and ReviewB. Regulatory Flexibility Act (RFA), as

amended by the Small BusinessRegulatory Enforcement Fairness Act of1996 (SBREFA), 5 U.S.C. 601 et seq.

C. Submission to Congress and the GeneralAccounting Office

D. Paperwork Reduction ActE. Unfunded Mandates Reform ActF. Executive Order 13084: Consultation

and Coordination with Indian TribalGovernments

G. Executive Order 13132: FederalismH. National Technology Transfer and

Advancement ActI. Executive Order 13045: Protection of

Children from Environmental HealthRisks and Safety Risks



J. Executive Order 13158: Marine ProtectedAreas

X. Regulatory ImplementationA. Implementation of Limitations and

StandardsB. Upset and Bypass ProvisionsC. Variances and ModificationsD. Relationship of Effluent Limitations to

NPDES Permits & MonitoringRequirements

E. Analytical MethodsAppendix A: Definitions, Acronyms, andAbbreviations Used in This Preamble

I. Legal Authority

EPA is promulgating these regulationsunder the authority of sections 301, 304,306, 307, 308, 402, and 501 of the CleanWater Act, 33 U.S.C. 1311, 1314, 1316,1317, 1318, 1342 and 1361. Thetechnical amendment to part 9 ispromulgated under the authority of 7U.S.C. 135 et seq., 136–136y; 15 U.S.C.2001, 2003, 2005, 2006, 2601–2671; 21U.S.C. 331j, 346a, 348; 31 U.S.C. 9701;33 U.S.C. 1251 et seq., 1311, 1313d,1314, 1318, 1321, 1326, 1330, 1342,1344, 1345 (d) and (e), 1361; E.O. 11735,38 FR 21243, 3 CFR, 1971–1975 Comp.p. 973; 42 U.S.C. 241, 242b, 243, 246,300f, 300g, 300g–1, 300g–2, 300g–3,300g–4, 300g–5, 300g–6, 300j–1, 300j–2,300j–3, 300j–4, 300j–9, 1857 et seq.,6901–6992k, 7401–7671q, 7542, 9601–9657, 11023, 11048.

II. Background

A. Clean Water Act

Congress adopted the Clean Water Act(CWA) to ‘‘restore and maintain thechemical, physical, and biologicalintegrity of the Nation’s waters’’(Section 101(a), 33 U.S.C. 1251(a)). Toachieve this goal, the CWA prohibits thedischarge of pollutants into navigablewaters except in compliance with thestatute. The Clean Water Act confrontsthe problem of water pollution on anumber of different fronts. Its primaryreliance, however, is on establishingrestrictions on the types and amounts ofpollutants discharged from variousindustrial, commercial, and publicsources of wastewater.

Direct dischargers must comply witheffluent limitations in NationalPollutant Discharge Elimination System(‘‘NPDES’’) permits; indirect dischargersmust comply with pretreatmentstandards. These limitations andstandards are established by regulationfor categories of industrial dischargersand are based on the degree of controlthat can be achieved using variouslevels of pollution control technology.

1. Best Practicable Control TechnologyCurrently Available (BPT)—Section304(b)(1) of the CWA

Section 304(b)(1)(A) of the CWArequires EPA to identify effluentreductions attainable through theapplication of, ‘‘best practicable controltechnology currently available forclasses and categories of point sources.’’Generally, EPA determines BPT effluentlevels based upon the average of the bestexisting performances by plants ofvarious sizes, ages, and unit processeswithin each industrial category orsubcategory. In industrial categorieswhere present practices are uniformlyinadequate, however, EPA maydetermine that BPT requires higherlevels of control than any currently inplace if the technology to achieve thoselevels can be practicably applied (see ALegislative History of the Federal WaterPollution Control Act Amendments of1972, U.S. Senate Committee of PublicWorks, Serial No. 93–1, January 1973, p.1468).

In addition, CWA Section 304(b)(1)(B)requires a cost assessment for BPTlimitations. In determining the BPTlimits, EPA must consider the total costof treatment technologies in relation tothe effluent reduction benefits achieved.This inquiry does not limit EPA’s broaddiscretion to adopt BPT limitations thatare achievable with available technologyunless the required additionalreductions are ‘‘wholly out ofproportion to the costs of achievingsuch marginal level of reduction.’’ (seeLegislative History, op. cit. p. 170).Moreover, the inquiry does not requirethe Agency to quantify benefits inmonetary terms (e.g., American Iron andSteel Institute v. EPA, 526 F. 2d 1027(3rd Cir., 1975)).

In balancing costs against the benefitsof effluent reduction, EPA considers thevolume and nature of expecteddischarges after application of BPT, thegeneral environmental effects ofpollutants, and the cost and economicimpacts of the required level ofpollution control. In developingguidelines, the Act does not requireconsideration of water quality problemsattributable to particular point sources,or water quality improvements inparticular bodies of water.

2. Best Available TechnologyEconomically Achievable (BAT)—Section 304(b)(2) of the CWA

The CWA establishes BAT as aprincipal means of controlling thedischarge of toxic and non-conventionalpollutants. In general, BAT effluentlimitations guidelines represent the bestexisting economically achievable

performance of direct discharging plantsin the industrial subcategory orcategory. The factors considered inassessing BAT include the cost ofachieving BAT effluent reductions, theage of equipment and facilitiesinvolved, the processes employed,engineering aspects of the controltechnology, potential process changes,non-water quality environmentalimpacts (including energyrequirements), and such factors as theAdministrator deems appropriate. TheAgency retains considerable discretionin assigning the weight to be accordedto these factors. An additional statutoryfactor considered in setting BAT iseconomic achievability. Generally, theachievability is determined on the basisof the total cost to the industrialsubcategory and the overall effect of therule on the industry’s financial health.BAT limitations may be based uponeffluent reductions attainable throughchanges in a facility’s processes andoperations. As with BPT, where existingperformance is uniformly inadequate,BAT may be based upon technologytransferred from a different subcategorywithin an industry or from anotherindustrial category. BAT may be basedupon process changes or internalcontrols, even when these technologiesare not common industry practice.

3. Best Conventional Pollutant ControlTechnology (BCT)—Section 304(b)(4) ofthe CWA

The 1977 amendments to the CWArequired EPA to identify effluentreduction levels for conventionalpollutants associated with BCTtechnology for discharges from existingindustrial point sources. BCT is not anadditional limitation, but replaces BestAvailable Technology (BAT) for controlof conventional pollutants. In additionto other factors specified in section304(b)(4)(B), the CWA requires that EPAestablish BCT limitations afterconsideration of a two part ‘‘cost-reasonableness’’ test. EPA explained itsmethodology for the development ofBCT limitations in July 1986 (51 FR24974).

Section 304(a)(4) designates thefollowing as conventional pollutants:biochemical oxygen demand (BOD5),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).



4. New Source Performance Standards(NSPS)—Section 306 of the CWA

NSPS reflect effluent reductions thatare achievable based on the bestavailable demonstrated controltechnology. New facilities have theopportunity to install the best and mostefficient production processes andwastewater treatment technologies. As aresult, NSPS should represent thegreatest degree of effluent reductionattainable through the application of thebest available demonstrated controltechnology for all pollutants (i.e.,conventional, non-conventional, andpriority pollutants). In establishingNSPS, EPA is directed to take intoconsideration the cost of achieving theeffluent reduction and any non-waterquality environmental impacts andenergy requirements.

5. Pretreatment Standards for ExistingSources (PSES)—Section 307(b) of theCWA

PSES are designed to prevent thedischarge of pollutants that passthrough, interfere with, or are otherwiseincompatible with the operation ofpublicly owned treatment works(POTWs). The CWA authorizes EPA toestablish pretreatment standards forpollutants that pass through POTWs orinterfere with treatment processes orsludge disposal methods at POTWs.Pretreatment standards are technology-based and analogous to BAT effluentlimitations guidelines.

The General PretreatmentRegulations, which set forth theframework for implementing categoricalpretreatment standards, are found at 40CFR part 403. Those regulations containa definition of pass through thataddresses localized rather than nationalinstances of pass through and establishpretreatment standards that apply to allnon-domestic dischargers. See 52 FR1586, January 14, 1987.

6. Pretreatment Standards for NewSources (PSNS)—Section 307(b) of theCWA

Like PSES, PSNS are designed toprevent the discharges of pollutants thatpass through, interfere with, or areotherwise incompatible with theoperation of POTWs. PSNS are to beissued at the same time as NSPS. Newindirect dischargers have theopportunity to incorporate into theirplants the best available demonstratedtechnologies. The Agency considers thesame factors in promulgating PSNS as itconsiders in promulgating NSPS.

7. Best Management Practices (BMPs)Sections 304(e), 308(a), 402(a), and

501(a) of the CWA authorize the

Administrator to prescribe BMPs as partof effluent limitations guidelines andstandards or as part of a permit. EPA’sBMP regulations are found at 40 CFR122.44(k). Section 304(e) of the CWAauthorizes EPA to include BMPs ineffluent limitations guidelines forcertain toxic or hazardous pollutants forthe purpose of controlling ‘‘plant siterunoff, spillage or leaks, sludge or wastedisposal, and drainage from rawmaterial storage.’’ Section 402(a)(1) andNPDES regulations (40 CFR 122.44(k))also provide for best managementpractices to control or abate thedischarge of pollutants when numericlimitations and standards are infeasible.In addition, section 402(a)(2), read inconcert with section 501(a), authorizesEPA to prescribe as wide a range ofpermit conditions as the Administratordeems appropriate in order to ensurecompliance with applicable effluentlimitations and standards and suchother requirements as the Administratordeems appropriate.

8. CWA Section 304(m) RequirementsSection 304(m) of the CWA, added by

the Water Quality Act of 1987, requiresEPA to establish schedules for: (1)Reviewing and revising existing effluentlimitations guidelines and standards;and (2) promulgating new effluentguidelines. On January 2, 1990, EPApublished an Effluent Guidelines Plan(55 FR 80), in which schedules wereestablished for developing new andrevised effluent guidelines for severalindustry categories, including the oiland gas extraction industry. NaturalResources Defense Council, Inc.,challenged the Effluent Guidelines Planin a suit filed in the U.S. District Courtfor the District of Columbia, (NRDC etal. v. Browner, Civ. No. 89–2980). OnJanuary 31, 1992, the Court entered aconsent decree (the ‘‘304(m) Decree’’),which establishes schedules for, amongother things, EPA’s proposal andpromulgation of effluent guidelines fora number of point source categories. Themost recent Effluent Guidelines Planwas published in the Federal Registeron August 31, 2000 (65 FR 53008). Thisplan requires, among other things, thatEPA take final action regarding theSynthetic-Based Drilling FluidsGuidelines by December 2000.

B. Pollution Prevention ActThe Pollution Prevention Act of 1990

(PPA) (42 U.S.C. 13101 et seq., PublicLaw 101–508, November 5, 1990)‘‘declares it to be the national policy ofthe United States that pollution shouldbe prevented or reduced wheneverfeasible; pollution that cannot beprevented should be recycled in an

environmentally safe manner, wheneverfeasible; pollution that cannot beprevented or recycled should be treatedin an environmentally safe mannerwhenever feasible; and disposal orrelease into the environment should beemployed only as a last resort * * *’’(Sec. 6602; 42 U.S.C. 13101 (b)). Inshort, preventing pollution before it iscreated is preferable to trying to manage,treat or dispose of it after it is created.The PPA directs the Agency to, amongother things, ‘‘review regulations of theAgency prior and subsequent to theirproposal to determine their effect onsource reduction’’ (Sec. 6604; 42 U.S.C.13103(b)(2)). EPA reviewed this effluentguideline for its incorporation ofpollution prevention.

According to the PPA, sourcereduction reduces the generation andrelease of hazardous substances,pollutants, wastes, contaminants, orresiduals at the source, usually within aprocess. The term source reduction‘‘include(s) equipment or technologymodifications, process or proceduremodifications, reformulation or redesignof products, substitution of rawmaterials, and improvements inhousekeeping, maintenance, training orinventory control. The term ‘‘sourcereduction’’ does not include anypractice which alters the physical,chemical, or biological characteristics orthe volume of a hazardous substance,pollutant, or contaminant through aprocess or activity which itself is notintegral to or necessary for theproduction of a product or the providingof a service.’’ 42 U.S.C. 13102(5). Ineffect, source reduction means reducingthe amount of a pollutant that enters awaste stream or that is otherwisereleased into the environment prior toout-of-process recycling, treatment, ordisposal.

In these final regulations, EPAsupports pollution preventiontechnology by encouraging theappropriate use of synthetic-baseddrilling fluids (SBFs) based on the useof base fluid materials in place oftraditional: (1) Water-based drillingfluids (WBFs); and (2) oil-based drillingfluids (OBFs) consisting of diesel oil/orand mineral oil. The appropriate use ofSBFs in place of WBFs will generallylead to more efficient and faster drillingand a per well reduction in non-waterquality environmental impacts(including energy requirements) anddischarged pollutants. Use of SBFs mayalso lead to a reduced demand for newdrilling rigs and platforms anddevelopment well drilling though theuse directional and extended reachdrilling. Discharges from SBF-drillingoperations have lower aqueous and



sediment toxicities, lowerbioaccumulation potentials, and fasterbiodegradation rates as compared toOBFs. In addition, polynuclear aromatichydrocarbons (PAHs), including thosewhich are priority pollutants, which areconstituents in OBFs are not present inSBFs.

EPA considered a ‘‘zero discharge’’requirement (i.e., BAT/NSPS Option 3)for SBF-cuttings wastes and determinedthat under this requirement mostoperators would decrease the use ofSBFs in favor of OBFs and WBFs due tolower OBF and WBF drilling fluid unitcosts. EPA concluded that a zerodischarge requirement for SBF-cuttingsand the subsequent increased use ofOBFs and WBFs would result in: (1)Unacceptable non-water qualityenvironmental impacts (NWQIs); and (2)more pollutant loadings to the oceandue to operators switching from SBFs toless efficient WBFs.

The appropriate use of SBF in placeof OBF will generally shorten the lengthof the drilling project and eliminate theneed to barge to shore or re-inject OBF-waste cuttings, thereby reducing NWQIsuch as fuel use, air emissions, and landdisposal of OBFs. The controlleddischarge option also eliminates the riskof OBF and OBF-cuttings spills andcross-media contamination at landdisposal operations. Operators would beincreasing the toxicity of their drillingfluids and wastes by using OBFs inplace of SBFs. As stated in April 2000(65 FR 21557), EPA used SBF and OBFspill data in the final rule as a factor insupporting a controlled dischargeoption. U.S. Department of Interior,Minerals Management Service (MMS)spill data show that riser disconnects indeep water drilling can releaseapproximately 2,400 barrels of neat SBFand these incidences occur in deepwater on average two to three times peryear due to riser failure (Docket No. W–98–26, Record No. IV.B.a.3). Riserdisconnects in the deep water are aparticular concern due to: (1) Increasedriser tensioning; (2) deep watertechnical requirements (e.g., riserverticality, increased use of top drivesystems, multiple flex joints in riser,placement of well heads and uppercasing sections in soft sea beds); and (3)deep water ocean environments (e.g.,uncharted eddy and loop currents)(Docket No. W–98–26, Record No.IV.B.a.4; Record No. IV.B.a.5). Use ofWBFs in place of SBFs would also leadto: (1) An increase in NWQIs due to theincreased length of the drilling project;and (2) a per well increase pollutantsdischarged due to poorer technicalperformance of WBFs. For these primary

reasons, EPA rejected the zero dischargeoption.

In addition, the technology controls inthe final regulation are based on a moreefficient solids control technology toincrease recycling of SBF in the drillingoperation. Increased SBF recyclingreduces the quantity of SBF required fordrilling operations and the quantity ofSBF discharged with drill cuttings. Adiscussion of this pollution preventiontechnology is contained in Section V.Aof this preamble and in the SBFDevelopment Document.

C. Profile of Industry

1. Well Drilling Process Description

The SBF Development Documentpresents a thorough description of theindustry including drilling practices,solids control systems, and wastedisposal operations. The followingsummary is excerpted from thattechnical document.

Drilling occurs in two phases:exploration and development.Exploration activities are thoseoperations involving the drilling ofwells to locate hydrocarbon bearingformations and to determine the sizeand production potential ofhydrocarbon reserves. Developmentactivities involve the drilling ofproduction wells once a hydrocarbonreserve has been discovered anddelineated.

Drilling for oil and gas is generallyperformed by rotary drilling methodswhich use a circularly rotating drill bitthat grinds through the earth’s crust asit descends. Drilling fluids are pumpeddown through the drill bit via a pipethat is connected to the bit, and serve tocool and lubricate the bit duringdrilling. The rock chips that aregenerated as the bit drills through theearth are termed ‘‘drill cuttings’’ orsimply ‘‘cuttings.’’ The drilling fluidalso serves to transport the drill cuttingsback up to the surface through the spacebetween the drill pipe and the well wall(this space is termed the annulus), inaddition to controlling downholepressure and stabilizing the well bore.

As drilling progresses, large pipescalled ‘‘casing’’ are inserted into thewell to line the well wall. Drillingcontinues until the hydrocarbon bearingformations are encountered. In areaswhere drilling fluids and drill cuttingsare allowed to be discharged under thecurrent regulations, well depths rangefrom approximately 4,000 to 12,000 feetdeep, and it takes approximately 20 to60 days to complete drilling.

On the surface, the drilling fluid anddrill cuttings undergo an extensiveseparation process to remove fluid from

the cuttings. The fluid is then recycledinto the system, and the cuttingsbecome a waste product. The drillcuttings retain a certain amount of thedrilling fluid that are discharged ordisposed with the cuttings. Drillcuttings are discharged by the shaleshakers and other solids separationequipment (e.g., decanting centrifuges,mud cleaners, cuttings dryers). Drillcuttings are also cleaned out of the mudpits and from the solid separationequipment during displacement of thedrilling fluid system (i.e., accumulatedsolids). Intermittently during drilling,and at the end of the drilling process,drilling fluids may become wastes ifthey can no longer be reused orrecycled.

In the relatively new area of ultra-deep water drilling (i.e., water depthsgreater than 3,000 feet), new drillingmethods are evolving which cansignificantly improve drillingefficiencies and thereby reduce NWQIs(e.g., fuel, steel casing consumption, airemissions) and the per well amount ofpollutants discharged. Subsea drillingfluid boosting, referred to as ‘‘dualgradient drilling,’’ is one such newdrilling technology. Dual gradientdrilling is similar to traditional rotarydrilling methods as previouslydescribed with the exception that thedrilling fluid is energized or boosted byuse of a pump at or near the seafloor.By boosting the drilling fluid, theadverse effect on the wellbore caused bythe drilling fluid pressure from theseafloor to the surface is eliminated,thereby allowing wells to be drilledwith as much as a 50% reduction in thenumber of casing strings generallyrequired to line the well wall. As aresult of the reduced number of casingstrings, dual gradient wells can bedrilled almost one-third faster and withsmaller hole sizes than conventionaldeep water drilling. Smaller hole sizesand faster drilling translate into fewerpollutants being discharged to the oceanand fewer NWQI. Dual gradient drillingtechnology can also potentiallyeliminate or reduce the amount ofwhole drilling fluid released to theenvironment during an inadvertent riserdisconnect. Finally, dual gradientdrilling technology can greatly reducethe potential release of drilling fluidwhen drilling through shallow sandintervals (e.g., shallow water flow)(Docket No. W–98–26, Record No.IV.B.a.6).

Some dual gradient drilling systemsrequire the separation of the largestcuttings (e.g., larger than approximately1⁄4 inch) at the seafloor since thesecuttings may interfere with the rotatoryaction of subsea pumps (e.g., electrical



submersible pumps). The larger cuttingsare routed at the seafloor to a venturiaction pump (with no moving parts),mixed with seawater, and pumped to acuttings discharge hose at the seafloorwithin a 300 foot radius of the well site.The hose is perforated on the last 50 ftof its length to maximize the spread ofcuttings. The action of pumping cuttingswith seawater can be expected to havesome cleaning and dispersion effect. Aremotely operated vehicle (ROV) canalso be used to reposition the subseadischarge hose to maximize cuttingsdispersal. Representative samples ofdrill cuttings discharged at the seafloorcan be transported to the surface by aROV for purposes of monitoring. Thedrilling fluid, which is boosted at theseafloor and transports most of the drillcuttings (e.g., 95–98% of total cuttingsgenerated) back to the surface, isprocessed as described in the generalrotary drilling methods described abovein this section.

A commercial potential determinationis made at the completion of rotarydrilling (i.e., once the target oil ornatural gas formations have beenreached). The well is then made readyfor production by a process termed‘‘completion.’’ Completion involvescleaning the well to remove drillingfluids and debris, perforating the casingthat lines the producing formation,inserting production tubing to transportthe hydrocarbon fluids to the surface,and installing the surface wellhead. Thewell is then ready for production (i.e.,actual extraction of hydrocarbons).

2. Location and ActivityThis rule establishes effluent

limitations guidelines and standardsthat control discharges of SBF and SBF-cuttings throughout the Offshoresubcategory beyond three miles fromshore, except for Offshore Alaska whereno three mile restriction applies. Thisrule prohibits discharge of SBF andSBF-cuttings in Upper (CoastalSubcategory) Cook Inlet, Alaska, unlessoperators meet criteria demonstratingthat they are unable to: (1) Box and storetheir cuttings on-site for zero dischargecuttings transfer operations (i.e., haul toshore for land disposal or re-injection atanother rig or platform); or (2) re-injecttheir SBF-cuttings on-site. When CoastalCook Inlet, AK, operators demonstrateto the NPDES controlling authority thatthey are unable to achieve zerodischarge of their SBF-cuttings, theymay discharge their SBF-cuttings underthe same controls as exist for SBF-cuttings discharges in Offshore waters.Criteria for establishing when operatorscannot achieve zero discharge areestablished in the final regulation. SBF-

cuttings discharged in Offshore CookInlet, Alaska, are controlled in the samemanner as other SBF-cuttings in otherOffshore waters. This rule does notamend the requirements for zerodischarge of drilling fluids and drillcuttings where they have already beenprohibited from discharge.

Drilling is currently active in threeregions: (1) The offshore waters beyondthree miles from shore in the Gulf ofMexico (GOM); (2) offshore watersbeyond three miles from shore inCalifornia; and (3) Cook Inlet, Alaska.Most drilling activity occurs in theGOM, where 1,302 wells were drilled in1997, compared to 28 wells drilled inCalifornia and 7 wells drilled in CookInlet. In the GOM, over the last fewyears, there has been high growth in thenumber of wells drilled in deep water(e.g., water depths greater than 1,000feet). For example, in 1995, 84 wellswere drilled in deep water, comprising8.6% of all GOM wells drilled that year.By 1997, that number increased to 173deep water wells drilled and comprisedover 13% of all GOM wells drilled. Mostrecent 1999 data show that this trend iscontinuing as over 15% of all GOMwells drilled were in deep water. Theincreased activity in deep waterincreases the usefulness of SBFs.Operators drilling in deep water cite thefollowing factors for selecting SBFs overWBFs and OBFs: (1) Potential for riserdisconnect (i.e., inadvertent releases ofdrilling fluid) in floating drill ships,which favors SBF over OBF; (2) higherdaily drilling cost which more easilyjustifies use of more expensive SBFsover WBFs; and (3) greater distance tobarge drilling wastes that may not bedischarged (i.e., OBFs, WBFs that failthe SPP Toxicity Test as currentlyrequired by EPA in Appendix 2 toSubpart A of 40 CFR part 435).

3. Drilling Wastestreams

Drilling fluids and drill cuttings are amajor source of waste from exploratoryand development well drillingoperations. This final regulationestablishes limitations for both thedrilling fluid and the drill cuttingswastestream when SBFs are used. Allother wastestreams and drilling fluids(e.g., WBFs, OBFs) already havelimitations; those limitations are outsidethe scope of this rule. Thecharacteristics of both drilling fluidsand drill cuttings wastestreams aresummarized in Section V.A of thispreamble. A more detailed discussion ofthe origins and characteristics of thesewastes is also included in the SBFDevelopment Document.

D. Proposed RuleOn February 3, 1999 (64 FR 5488),

EPA published proposed effluentlimitations guidelines for the dischargeof SBF drilling fluids and drill cuttingsinto waters of the United States byexisting and new facilities in the oil andgas extraction point source category.

EPA received comments on manyaspects of the proposal. The majority ofcomments related to: (1) The proposedanalytical test methods for stock anddischarge limitations; (2) equipmentused to set BAT and NSPS cuttingsretention limitations; (3) BestManagement Practices (BMPs) and theiruse to control small volume spills andreleases of SBF; (4) the proposal’sengineering and economic modelingparameters; and (5) procedural anddefinition issues. EPA evaluated all ofthese issues based on additionalinformation collected by EPA orreceived during the comment period.EPA then discussed the results of theseevaluations in a Notice of DataAvailability which is discussed below.

E. Notice of Data AvailabilityOn April 21, 2000 (65 FR 21548), EPA

published a Notice of Data Availability(NODA) to present a summary of newdata received in comments on theproposed rule or collected by EPAfollowing publication of the proposal. Inthe April 2000 NODA, EPA discussedthe major issues and presented severalrevised modeling and alternativeapproaches to address these issues. EPAsolicited comment on the data collectedsince proposal and on the revisedmodeling and alternative approaches tomanage SBF discharges.

III. Summary of Data and InformationReceived in Response to the Notice ofData Availability

The April 2000 NODA summarizedthe data and information received byEPA in response to the February 1999proposal and information receivedbefore the April 2000 NODA. Thissection describes the data received byEPA in response to the April 2000NODA.

A. Pollutant Loading and Numeric LimitAnalyses

1. SBF Retention on CuttingsSBF retention on cuttings (ROC) data

quantify the amount of SBF retained oncuttings (mass of SBF/mass of wetcuttings, expressed as a percentage).Lower ROC values indicate less SBFretained on cuttings. EPA uses ROCdata, along with other engineeringfactors (e.g., installation requirements,fluid rheology) to evaluate the



performance of various solids controltechnologies.

In response to the February 1999proposal, industry submitted data forSBF ROC from 36 wells. EPAdetermined that 16 files were completeand accurate, and these data werepresented in the April 2000 NODA. EPArejected six files due to incompletereporting. EPA received 14 files too latefor inclusion in the April 2000 NODAanalyses.

In response to the April 2000 NODA,EPA received and evaluated ROC datafrom an additional 79 SBF wells: the 14received after the February 1999proposal comment period; 27 additionalsets received during the April 2000NODA comment period; and 38received after the April 2000 NODAcomment period. EPA determined thatdata from 49 of these 79 wells werecomplete for inclusion in the final ruleanalyses. Therefore, EPA used data from65 wells to determine the ROCperformance of the various solidscontrol technologies. The collection,engineering review, and extraction ofdata from these files are described in theSBF Development Document.

EPA revised the average ROC valuesof various solids control technologiesbased on the final ROC data. Theserevised average ROC values werecombined to yield the average ROCvalue for the following three SBF-cuttings technology options: (1) BAT/NSPS Option 1 is based on the use ofshale shakes, cuttings dryer, finesremoval unit, and discharges from thecuttings dryer and fines removal unitand has a long-term average ROC valueof 4.03%; (2) BAT/NSPS Option 2 isbased on the use of shale shakes,cuttings dryer, and fines removal unit,and one discharge from the cuttingsdryer, and has a long-term average ROCvalue of 3.82%; and (3) BAT/NSPSOption 3 is based on the use of shaleshakes, cuttings boxes, barges, and zerodischarge land disposal and offshore re-injection and has a long-term averageROC value of 10.2%. In addition, usingthe ROC data, EPA developed a BATlimitation and standard controlling thebase fluid retained on cuttings fordrilling fluids with the environmentalperformance of esters (e.g.,biodegradation, sediment toxicity). EPAdeveloped this option to provideoperators an incentive to use ester-basedSBFs and has a long-term average ROCvalue of 4.8%. EPA used the ROC datato establish a BAT limitation and aNSPS on base fluid retained on cuttings.The base fluid retained on cuttingslimitation and standard bothincorporate the variability of solids

control efficiencies and are higher thanthe long term average.

2. Days to Drill

EPA uses the number of days to drillthe SBF interval, for all four modelwells, as an input parameter in theNWQI and cost analysis. EPA extractedrelevant data from each of the 65 wellsidentified above to estimate the numberof days to drill each of the four modelwell SBF intervals (Docket No. W–98–26, Record No. IV.B.a.7). The revisednumbers of days required to drill theSBF model wells are based on a revisedaverage rate of SBF-cuttings generation(i.e., 108.7 bbls wet cuttings/day). Therevised numbers of days required todrill the SBF model wells are: (1) 5.2days for shallow-water developmentwells (SWD); (2) 10.9 days for shallow-water exploratory wells (SWE); (3) 7.9days for deep-water development wells(DWD); and (4) 17.5 days for deep-waterexploratory wells (DWE).

3. Well Count Projections Over NextFive Years

EPA revised well count projectionsfor Offshore GOM, Offshore California,and Cook Inlet, AK, based oninformation submitted by industry(Docket No. W–98–26, Record No.IV.B.a.9; Record No. IV.B.a.10; RecordNo. IV.B.a.11). The revised annual wellcounts are 1,047 shallow water wellsand 138 deep water wells in OffshoreGOM; 7 shallow water wells and nodeep water wells in Offshore California;and 6 shallow water wells and no deepwater wells in Cook Inlet, AK. Theserevised well counts are not significantlydifferent from the well counts used inthe February 1999 proposal and April2000 NODA (i.e., see SBF ProposalDevelopment Document (EPA–821–B–98–021), Table IV–2: 1,022 shallowwater wells and 139 deep water wellsacross the GOM, Offshore California,and Cook Inlet, AK).

Industry only provided the wellcounts in terms of shallow water versusdeep water wells. EPA further dividedthe revised well counts intodevelopment and exploratory wellcategory counts for estimating pollutantloadings, compliance costs, and NWQIs.EPA performed this allocation usingprior well count data from the April2000 NODA. EPA derived percentagesof development versus exploratory wellsfor both shallow water well types anddeep water well types. EPA thenapplied these percentages to the revisedaggregated shallow water and deepwater well counts provided by industry.EPA also collected additional washoutrates for WBF and SBF drilling.

EPA also revised well countprojections to reflect enhanceddirectional drilling capabilities whenusing SBF. EPA received informationthat SBF directional drilling can reducethe number of wells required to drill adevelopment well project. Specifically,industry stated that SBF developmentdrilling can generally reduce the drilledfootage required for full development ofa typical reservoir by one-third ascompared with WBF drilling (DocketNo. W–98–26, Record No. IV.B.a.9). EPAhas included this consideration byreducing the footage drilled by one-thirdfor WBF development wells projected toconvert from WBF to SBF under the twocontrolled discharge options.

4. Current and Projected OBF, WBF, andSBF Use Ratios

For the February 1999 proposal andApril 2000 NODA, EPA estimated that80% of the average annual GOM wellsare drilled using WBF exclusively; 10%are drilled with SBF; and 10% aredrilled with OBF. EPA also included inwell counts estimates of operatorsconverting from OBF to SBF or SBF toOBF under each of the SBF-cuttingscontrolled discharge options.

For the final rule, EPA revised therelative frequency of use between WBF,OBF, and SBF under the two dischargeoptions and the zero discharge optionbased on data submitted by industry(Docket No. W–98–26, Record No.IV.B.a.9; Record No. IV.B.a.10; RecordNo. IV.B.a.11). Industry supplied thisinformation to EPA in several formats.EPA used the most reliable information(e.g., the actual well count data forWBF, OBF, and SBF wells over a periodof three years) to estimate drilling fluiduse under each of the SBF-cuttingscontrol options (see SBF DevelopmentDocument).

EPA believes that some operatorswould switch from WBFs to SBFs forcertain wells due to the increasedefficiency of SBF drilling. While nogood industry average statistics exist, itis generally considered that SBFs reduceoverall drilling time by 50% (e.g., if awell took 60 days to drill with WBF, thesame well should be able to be drilledwith SBF in 30 days) (Docket No. W–98–26, Record No. IV.B.a.9; Record No.IV.B.a.10; Record No. IV.B.a.11).Reducing drilling time generallyreduces drilling costs. However, not alldrilling operators will switch fromWBFs to SBF due to a variety of otherfactors, (e.g., WBFs are less expensive(per barrel) than SBFs, potential for lostcirculation downhole).

Additionally, EPA believes that underthe SBF-cuttings zero discharge option,not all operators would switch from



SBFs to OBFs but that some operatorswould switch to WBFs. Some drillingoperations require the technicalperformance of non-aqueous drillingfluids and operators must select eitheran OBF or SBF. Therefore, for thesedrilling operations, operators wouldselect OBFs in place of SBF under theSBF-cuttings zero discharge option asOBFs are less expensive (per barrel)than SBFs. However, some drillingoperations could use either WBFs oroleaginous drilling fluids such as OBFs,enhanced mineral oil based drillingfluids, or SBFs. Depending on a varietyof site specific factors (e.g., formationcharacteristics, directional drillingrequirements, torque and dragrequirements), operators may selectWBFs in lieu of SBFs or OBFs under theSBF-cuttings zero discharge option.

5. Waste Volumes and Characteristics

EPA collected additional data toidentify the volumes and characteristicsof WBF discharges. This additional datamore adequately describes the totalamount of pollutants loadings andNWQI under each of the three SBF-cuttings management options. Forexample, under the SBF zero dischargeoption (BAT/NSPS Option 3) operatorswould more likely choose WBF andOBF over SBF due primarily to therelatively higher unit cost of SBF.

Different pollutant loadings andNWQI are expected for WBF ascompared with either OBF or SBF wellsbased on differences in washout andlength of drilling time. EPA anticipatesa reduction in cuttings waste volumewhen comparing SBF-drilling to WBF-drilling based on greater hole washout(i.e., enlargement) in WBF drilling.Industry estimated that WBF washoutpercentages vary between 25% and75%, with 45% being an acceptableaverage and confirmed EPA’s SBF andOBF washout percentage of 7.5% asappropriate (Docket No. W–98–26,Record No. IV.B.a.9).

For the final rule, EPA also estimatedthat the barite used in SBF drilling isnearly pure barium sulfate (i.e., BaSO4)and, by gravimetric analysis, calculatedthe weight percentage of barium inbarite as 58.8%.

B. Compliance Costs Analyses

1. Equipment Installation andDowntime

For the April 2000 NODA, projectedcompliance costs for all optionsincluded equipment installation anddowntime for each SBF well drilled.After further review of ROC data wells(see Section III.A), EPA modified thisparameter in the final analyses to reflect

current practice of drilling multiplewells per year for any one equipmentinstallation (Docket No. W–98–26,Record No. IV.B.a.9). EPA reviewed theROC well data for the frequency ofmultiple wells on specified structures.EPA used the resulting well-per-structure analysis to adjust projectedannual SBF compliance costs byincluding the consideration of drillingmore than one SBF well per equipmentinstallation per year. EPA estimated that2.2 development wells per structure and1.6 exploratory wells per structure arecurrent industry practice, based onindustry-submitted data (see SBFDevelopment Document).

EPA received information on theability of operators to install cuttingsdryers (e.g., vertical or horizontalcentrifuges, squeeze press mud recoveryunits, High-G linear shakers) on existingGOM rigs (Docket No. W–98–26, RecordNo. IV.B.b.33). While some industrysources filed timely comments allegingthat some rigs could not accommodateadditional solids control equipment, inlate comments, industry provided dataconcerning the number of GOM rigs inoperation which are not capable ofhaving a cuttings dryer system installeddue to either rig space and/or rig designwithout prohibitive costs or rigmodifications.

EPA also received information on anew cuttings containment, handling,and transfer equipment system. Thenew system is designed to eliminate theneed to use cuttings boxes to handlecuttings. EPA received information fromone operator that recently field testedthe cuttings transfer system on one 121⁄4inch well section in the North Sea. Theoperator contained 100% of the cuttingson a rig (Alba) with limited deck space.Cuttings were handled in bulk belowdeck and pumped directly onto awaiting vessel for eventual landdisposal. The operator estimated thatuse of the new cuttings transfer systemeliminated hundreds of crane lifts andmanual handling issues and therebyimproved worker safety.

2. Current Drilling Fluid CostsIn response to the April 2000 NODA,

EPA revised unit costs of WBF, OBF,and SBF. Based on industry data, EPAused the WBF unit cost of $45 per barrelfor the final rule. The February 1999Proposal and April 2000 NODA usedOBF and SBF unit costs of $75 and $200per barrel of drilling fluid, respectively.Industry data indicates a range of OBFunit costs from $70–$90 per barrel andEPA used the OBF unit cost of $79 perbarrel for the final rule. EPA estimatesthat SBF unit costs will remain between$160 to $300 per barrel of drilling fluid

over the next few years. EPA used anSBF unit cost of $221 per barrel ofdrilling fluid for the final rule based onthe most frequently used SBF in theoffshore market.

3. Cost Savings of SBF Use as ComparedWith WBF Use

EPA revised its compliance costs toinclude the following factors: (1) Thecost savings associated with increasedrate of penetration when using SBF ascompared to WBF; and (2) the cost oflost WBFs that are discharged whiledrilling. EPA also examined, but did notinclude in its final compliance costimpacts, the costs associated withprojected failures of a fraction of WBFwells to meet sheen or toxicitylimitations, including costs of meetingzero discharge from these wells. EPAused this data to examine compliancecosts impacts if operators switch fromSBF to WBF drilling, or vice versa.

EPA requested data from industry onrate of penetration (ROP) for WBFoperations as compared to SBFoperations. Industry stated that ROPvalues of 300 feet per hour for SBF (andOBF) operations and 150 feet per hourfor WBF are reasonable averages.However, using these values over anentire well was not recommended ‘‘dueto the large number of variables’’(Docket No. W–98–26, Record No.IV.B.a.9). Industry’s information furtherstates that a generally-accepted estimateis that ‘‘SBFs reduce overall drillingtime by 50%’’ (Docket No. W–98–26,Record No. IV.B.a.9).

4. Construction Cost IndexEPA used the Construction Cost Index

(CCI) from the Engineering News andRecord (see http://www.enr.com/cost/costcci.asp) to reflect costs in 1999dollars rather than 1998 dollars as wasused for the April 2000 NODA. EPAused a CCI factor of 1.108 to reflect 1999dollars and a base year of 1995.

C. Economic Impacts AnalysesFor the final rule, EPA obtained and

used MMS data on drilling through1999 to identify any new firmsoperating in the offshore GOM anddetermine which firms were involved indeep water drilling operations. EPAidentified 17 additional firms newlydrilling in the GOM, of which 2 wereidentified as drilling in deep water. Ofthe new firms, 7 were identified as orassumed to be (for lack of data) smallentities. One of these seven small firmswas identified as a small entity drillingin deep water. This latter firm drilledtwo wells in the deep water in 1999.

EPA collected 1999 financialinformation on number of employees,



assets, equity, revenues, net income,return on assets, return on equity, andprofit margin for the publicly held,newly identified firms. EPA alsoupdated financial information for thepublicly held firms identified inFebruary 1999 proposal SBF EconomicAnalysis (EPA–821–B–98–020).

EPA also collected information on 13GOM onshore sites where offshore oiland gas drilling waste is handled ordisposed. This information consists ofprecise geographical location, amount ofwaste handled annually, and sitecapacity. This information was providedto EPA Region 6 for use in itsenvironmental justice (EJ) computermodel to screen for sites (i.e., Tier 1analysis) where disposal of additionaldrilling wastes under a zero dischargeoption might have environmental justiceimplications. EPA Tier 1 analysesidentified that five of the thirteenonshore facilities warranted additionalreview.

D. Water Quality Impact and HumanHealth Analyses

In response to April 2000 NODAcomments and information, EPA revisedthe water quality and human healthanalyses for the final rule based on: (1)Information on seabed surveys; (2)revised fish consumption rates; (3)information on Alaska state waterquality standards; and (4) revised ROCdata which affect EPA modeling ofwater quality, sediment quality, andhuman health impacts.

1. Seabed SurveysEPA received public comments

regarding the impact of SBF dischargeson the benthic environment. Severalseabed surveys were submitted to EPAtogether with the public comments.Information from two commentscontained specific seabed survey dataon sediment SBF concentrations afterdischarge of SBF cuttings. EPA includedadditional data from six wells in thecalculation of mean SBF sedimentconcentration (at 100 meters from themodeled discharge) used in the waterquality analysis. The mean SBFsediment concentration changed from14,741 mg/kg as published in the April2000 NODA to 9,718 mg/kg for modeledGulf of Mexico wells and from 8,655mg/kg to 13,052 mg/kg for wellsmodeled in Offshore California andCook Inlet, Alaska.

EPA also received information on theon-going joint Industry/MMS GOMseabed survey. The Industry/MMSworkgroup completed the first twocruises of the four cruise study in timefor EPA’s consideration for this finalrule. Cruise 1 was a physical survey of

10 GOM shelf locations, with theobjective of detection and delineation ofcuttings piles using physical techniques.Cruise 2 was to scout and screen thefinal 5 shelf and 3 deep water GOMwells chosen for the definitive studywhere SBF were used. The SBF-cuttingsdischarges included either internalolefins or LAO/ester blends. Bothcruises did not detect any large moundsof cuttings under any of the rigs orplatforms. Remotely operated vehicles(ROV) using video cameras and side-scanning sonar were used to conductthe physical investigations on theseabed. Video investigations onlydetected small cuttings clumps (<6″)around the base of some of the facilitiesand 1″ thick cuttings accumulations onfacility horizontal cross members.Outside of a 50–100′ radius from thefacility, no visible cuttingsaccumulations (large or small) weredetected at any of the facility surveysites.

Finally, EPA received a reportprepared for the MMS which provideda review of the scientific literature andseabed surveys to determine theenvironmental impacts of SBFs (DocketNo. W–98–26, Record No. IV.F.1). Theliterature report confirms EPA’s positionthat benthic communities will recoveras SBF concentrations in sedimentsdecrease and sediment oxygenconcentrations increase. The report alsoconfirms EPA’s position that withinthree to five years of cessation of SBF-cuttings discharges, concentrations ofSBFs in sediments will have fallen tolow enough levels and oxygenconcentrations will have increasedenough throughout the previouslyaffected area that complete recovery willbe possible.

2. Fish Consumption Rates

EPA revised the fish consumptionrates for use in environmentalassessment analyses. The consumptionrates vary depending on the fish habitatlocation (i.e., freshwater, estuarine, andmarine). EPA used the marine only fishconsumption rate for the finfishconsumption health risk analysis for theGulf of Mexico and Offshore California.EPA used the estuarine/marineconsumption rate for the Cook Inlet,Alaska analysis. EPA used theestuarine/marine consumption rate forall regions in the shrimp consumptionhealth risk analysis.

EPA also conducted an investigationinto the environmental factors affectingNative subsistence foods in Cook Inlet.EPA has incorporated relevantinformation from this investigation intothe SBF Environmental Assessment.

3. State Water Quality Standards

EPA evaluated the potential decreaseof water quality from the regulatorydischarge options and compared thepollutant concentrations torecommended Federal water qualitycriteria. For discharges occurring inCook Inlet, Alaska, EPA also comparedthe receiving water quality to Alaskastate water quality standards. EPA usedthe updated Alaska state standards forthe water quality analysis for Cook Inlet,Alaska.

E. Non-Water Quality EnvironmentalImpact Analyses

EPA received additional data affectingthe NWQI analyses in response to theApril 2000 NODA. These data includeadditional information on retention oncuttings and information regardingoffshore injection and onshore disposalpractices for each of the threegeographical areas: Gulf of Mexico,Offshore California, and Cook Inlet,Alaska.

EPA revised the average SBF retentionon cuttings for the discharge optionsbased on additional ROC data. Revisionsin ROC data affect the volume of SBF-cuttings generated. Consequently, EPArevised the amount of SBF-cuttings thatwill need to be treated under the twoSBF-cuttings controlled dischargeoptions (e.g., BAT/NSPS Options 1 and2). EPA also revised: (1) The amount ofSBF-fines that will need to be re-injected on-site or hauled to shore fordisposal under one of the SBF-cuttingscontrolled discharge option (e.g., BAT/NSPS Option 2); and (2) the amount ofSBF-fines and SBF-cuttings re-injectedon-site or hauled to shore for disposalunder the zero discharge option (BAT/NSPS Option 3).

EPA received additional SBF wellinterval data which was used to re-calculate the number of days to drill themodel SBF wells (see Section III.B.). Forthe NWQI analyses, the number of daysto drill the model wells serves as thebasis for estimating the length of timeequipment will be used to either treatthe cuttings before discharge or thehauling requirements under the zerodischarge option. The EPA NWQImodels estimate that air emissions andfuel use rates increase when the timerequired to complete a model well alsoincreases.

EPA obtained information regardingthe current practice of zero dischargedisposal for each of three geographicareas, Gulf of Mexico, OffshoreCalifornia, and Cook Inlet, Alaska (seeSection IV.D). Current practice indicatesthat most of the waste generated in theGulf of Mexico and Offshore California



and brought to shore is injectedonshore, whereas all of the wastecurrently generated in Cook Inlet isinjected offshore at the drilling site or ata near-by Class II Underground InjectionControl (UIC) disposal well. EPA alsoreceived from an on-shore injectionfacility specific equipment information,including the cuttings injection rate andcuttings grinding and injectionequipment power requirements and fuelrates (Docket No. W–98–26, Record No.IV.D.2).

Industry provided EPA withinformation regarding SBF use (seeSection III.A). One operator (Unocal)stated that it is starting to use SBF todrill the entire well and not justintervals in which WBFs presentproblems because drilling time can besignificantly reduced. EPA incorporatedthis information into the NWQI analysesby estimating the reduction of impactswhen using SBFs instead of WBFs. EPAalso received during the April 2000NODA comment period informationrelated to the average increase indrilling time (1.5 days) in order tocomply with zero discharge (Docket No.W–98–26, Record No. IV.A.a.3).

F. Compliance Analytical MethodsEPA completed additional studies in

response to the April 2000 NODA tosupport the development of analyticalmethods for determining sedimenttoxicity, biodegradation, and oilretention on cuttings. For sedimenttoxicity and biodegradation, EPAfocused specifically on optimizing testconditions (e.g., test duration, sedimentcomposition), discriminatory power,reproducibility, reliability, andpracticality. EPA’s sediment toxicitystudy provided toxicity data for bothpure base fluids and standard mudformulations of these base fluids. EPA’sbiodegradation study evaluated thedegradation of pure base fluids asdetermined by the solid phase test. Foroil retention on cuttings, EPAconducted studies to verify anddocument the sensitivity of the retorttest method.

During this same time period,industry sponsored Synthetic BasedMuds Research Consortium (SBMRC)conducted parallel studies on the samethree parameters (i.e., sediment toxicity,biodegradation, and base fluid retentionon cuttings). For sediment toxicity,industry provided extensive datacomparing a 4-day versus a 10-day testduration, natural versus syntheticsediments, as well as toxicity data onboth pure base fluids and mudformulations of these base fluids. Forbiodegradation, industry submittedresults from the closed bottle and

respirometry tests for biodegradation inaddition to the solid phase test. For oilretention on cuttings, Industry and EPAconducted rig-based method detectionlimit studies.

IV. Summary of Revisions Based onNotice of Data Availability Comments

A summary of significant revisions tothe analyses made by EPA in responseto the February 1999 proposal isprovided in the April 2000 NODA (see65 FR 21549, Sections III and IV). Thissection describes the revisions to theanalyses since publication of the April2000 NODA.

A. Pollutant Loading Analyses

1. Loadings for Water-Based DrillingFluids and Cuttings

For the final rule, EPA included thepollutant reductions (or increases) of thetechnology options based on operatorsswitching from OBFs or WBFs to SBFs(or vice versa) and used data containedin the Offshore Development Document(EPA–821–R–93–003). Waste volumeand/or pollutant loading data, on use ofOBFs and WBFs presented in theOffshore Development Document, wereexpressed on a ‘‘per bbl,’’ ‘‘per well,’’ ora ‘‘per day’’ basis. Data from theOffshore rule record included: (1) WBFcomposition; (2) waste volumes forWBFs, OBFs, and associated cuttings;(3) the frequency of mineral oil use inWBF operations; and (4) the expectedpermit limitation failure rates (primarilyfor toxicity) on mineral oil fluidsresulting in the requirement to haul orinject these wastes). These data thenwere applied to the current, revised wellcount projections and/or projectedwaste volumes to estimate dischargeoption loadings and the amount ofOBFs, WBFs, and associated cuttingsthat require zero discharge underexisting regulations (e.g., OBFscontaining diesel oil, WBFs that fail theSPP Toxicity Test). The OffshoreDevelopment Document providedinformation relevant to the inclusion ofWBFs in the final analyses including:(1) Frequency of WBFs that failedpermit limitations (Tables XI–10 andXI–7); (2) the composition of WBFs(Tables XI–3 and XI–6); (3) mineral oilcomposition (Table XI–5); and (4) thecomposition of cuttings from WBF(Section XI.3.4).

Industry-wide, regional, and totalloadings were calculated for theloadings analyses for this final rule fromthe revised well counts provided byindustry (Docket No. W–98–26, RecordNo. IV.B.a.9; Record No. IV.B.a.10;Record No. IV.B.a.11) combined withcomposition and estimated discharge

volumes for WBFs (OffshoreDevelopment Document, Table XI–2).

In the final loadings analyses, EPAalso corrected an error in the loadingmodel used for the April 2000 NODAanalyses. The error related to how EPAestimated the volume of fines from thefines removal unit captured and notdischarged under BAT/NSPS Option 2.The volume of fines is based on manyfactors including the hole size, washout,and the percentage of the total wetcuttings produced from the solidscontrol system that are fines. EPAincorrectly used the volume of drycuttings per model well in the April2000 NODA loading model to estimatethe volume of fines generated from theBAT/NSPS Option 2 solids controlsystem. The final loadings modelcorrectly uses the volume of wetcuttings per model well to estimate thevolume of fines generated from theBAT/NSPS Option 2 solids controlsystem. The correction of the error hadthe effect of increasing the amount offines captured for zero discharge underBAT/NSPS Option 2.

2. Drilling Fluid and CuttingsComposition and Density

The density of drilling wastes hauledin California was revised from 704 to716 pounds per barrel to reflect thecurrent density derived from the weightand volume data in the revised loadingsmodel. This results in a change in theunit cost to haul waste in California to$12.53 and $5.89 per barrel for disposaland handling costs, respectively.

3. Days to Drill

EPA revised the number of drillingdays based on data submitted inresponse to the April 2000 NODA foreach of the four model well types. Thenumber of drilling days input parameteraffects NWQI and compliance costs(e.g., equipment rental costs).

4. Directional Drilling

EPA also received additional dataconcerning the performance of SBFversus WBF for directional drillingoperations (Docket No. W–98–26,Record No. IV.B.a.9). EPA used thisinformation, the reduced number ofwells and total footage of SBF-drilleddevelopment wells, to estimatepollutant loading reductions resultingfrom WBF to SBF conversions. For eachof the two SBF-cuttings controlleddischarge options (i.e., BAT/NSPSOption 1 and 2), this revision reducedthe annual sum total of discharged WBFand WBF-cuttings.



B. Compliance Cost Analysis

1. Costs of WBFAs stated above, EPA modified the

cost analysis for the final rule to includeWBF cost factors. The WBF cost factorsthat EPA considered include: (1) Thecost of discharged WBFs and WBFassociated with cuttings dischargedonsite; (2) the projected occurrence ofmineral oil spots and/or lubrication andthe projected failure rate of thesemineral oil-amended fluids to meetpermit limitations on toxicity andsubsequent requirement to re-injectthese materials down hole or haul themfor onshore disposal; and (3) the rigcosts associated with increases ordecreases of drilling time related toWBF-to-SBF or SBF-to-WBFconversions over the projected intervalof SBF use.

The volumes of discharged WBF andassociated cuttings were estimated on aper well basis from data contained inthe Offshore Development Document(EPA–821–R–93–003) for Gulf ofMexico, California, and Cook Inlet, AKwells. A weighted average dischargevolume for each region, based onvolumes projected for shallow wells anddeep wells and the projected number ofwells for each, was derived to estimatethe volume of fluids and cuttingsdischarged onsite, per well, from WBFoperations. (Note: In the OffshoreDevelopment Document ‘‘shallow’’ and‘‘deep’’ refer to well depth, and are notthe same as ‘‘shallow’’ water and‘‘deep’’ water wells which refer to waterdepth in this final rule.) The volume ofadhering WBF on discharged cuttings,as contained in the OffshoreDevelopment Document, was estimatedat 5% of the total cuttings volume. Thecosts for these discharged WBFs werethen calculated from a per barrelestimate of average WBF cost. These perwell costs were then applied to the wellcount data in this final rule to deriveaggregate regional and total costs. Also,to assess lost fluid costs over theprojected SBF drilling interval, for thezero discharge option, the averagedischarge volumes per well wererecalculated as average dischargevolumes per day, based on the assumednumber of days (i.e., 20 days) used inthe Offshore Development Document fordrilling WBF wells.

The projected incidences of WBF withmineral oil spots, mineral oillubrication, or both mineral oil spot andlubrication were based on the OffshoreDevelopment Document estimates of thepercentages of projected wells in eachregion, projected shallow water versusdeep water wells, and the projectedincidence of spotting and lubrication.

These percentages were then applied tocurrent well count data for this finalrule. EPA used the OffshoreDevelopment Document rates of failure(i.e., exceeding permit toxicitylimitations) to project the currentnumber of wells that would requireonsite injection or onshore disposal ofmineral oil-amended WBF, and theirdisposal volumes were calculated fromper well volume estimates for WBFwells.

The effect of WBF-to-SBF conversion(anticipated under the dischargeoptions) and SBF-to-WBF conversion(anticipated under the zero dischargeoption) were derived from the estimatedduration (in days) of the SBF-drilledinterval. The projected number ofdrilling days was increased by a factorof 2 for each WBF model well to derivethe projected number of drilling daysthat would be required if WBFs wereused in place of SBFs. The incrementaldrilling time was used to estimatecompliance costs (e.g., increased rigcosts) associated with SBF-to-WBFconversions.

2. Equipment Installation andDowntime

In the April 2000 NODA, EPAestimated that each SBF well incurredcuttings dryer installation anddowntime costs. EPA revised thenumber of SBF wells drilled percuttings dryer equipment installationper year based on industry-suppliedROC data (see Section III.B.1). EPAconcluded that operators are drillingmultiple wells per year with the samecuttings dryer equipment installation.Consequently, EPA reduced the numberof cuttings dryer equipmentinstallations required to drill the annualnumber of SBF wells. For developmentwells, the average number of SBF wellsdrilled per cuttings dryer equipmentinstallation per year is 2.2. Forexploration wells, the average numberof SBF wells drilled per cuttings dryerequipment installation per year is 1.6.EPA incorporated these factors into thecompliance costs estimates and thesefactors reduced the overall cuttingsdryer equipment installation anddowntime costs for the industry.

3. Proportion of Hauled Versus InjectedWastes

EPA estimated in the April 2000NODA that 80% of drilling operationsin the GOM, Offshore California, andCook Inlet, Alaska, haul waste onshorewith the remaining 20% re-injectingthese wastes onsite. EPA used theseproportions to weight the average cost ofcomplying with zero discharge (i.e.,BAT/NSPS Option 3). EPA revised these

proportions based on additionalinformation received in response to theApril 2000 NODA (see Section IV.Ebelow) and updated the compliance costand NWQI models.

4. OBF and WBF Conversion to SBFEPA revised its compliance cost

model to incorporate the effect ofoperators switching from one type ofdrilling fluid to another under each ofthe three SBF-cuttings technologyoptions (see Section III.A.4). Generally,as compared with WBF and OBFs, SBFsled to a reduction in days required todrill a model well which leads to adecrease in drilling costs. Additionally,EPA revised the development drillingfootage estimate due to additionalinformation on the improved directionaldrilling capabilities of SBF over WBF.

C. Economic Impacts AnalysesIn response to the April 2000 NODA,

EPA identified that two projects usedfor economic modeling have shut in.Consequently, EPA removed these twoprojects from the economic analysis. Atotal of 18 projects remain for theeconomic modeling of existing projectsand 13 remain for the economicmodeling of new projects.

EPA added an environmental justice(EJ) analysis which investigates thepotential for impacts on minorities andsocioeconomically disadvantagedgroups under the zero discharge option.EPA performed a Tier 1 screeninganalysis, which combines geographiclocation and U.S. Census Bureau data todetermine the number of persons livingwithin 1 mile and 50 miles of drillingwaste handling and disposal sites, theirrace, and their socioeconomic status. Acomputer program developed by EPARegion 6 was used to rank andcharacterize sites on the basis ofwhether the populations near the sitecontain higher proportions of minorityand socioeconomically disadvantagedpersons than the state as a whole. Basedon scores derived for the 13 GOMonshore drilling waste handling anddisposal sites, EPA identified fivefacilities that could be potentiallyassociated with disproportionateimpacts on minorities orsocioeconomically disadvantagedgroups. EPA presents the results of theEJ analysis in Section IX.

D. Water Quality Impact and HumanHealth Analyses

EPA received comments regarding theheavy metal leach factors used in thewater quality impact analyses but didnot receive any specific data that couldbe used in the analyses (Docket No. W–98–26, Record No. IV.A.a.2). EPA



therefore did not change these factors.However, EPA reevaluated the modelingused in the proposal that metals forwhich there were no factors found inthe literature were completely insolublein the receiving water (i.e., the leachfactor would be zero). EPA estimatedthat these heavy metals would not beless soluble than iron which has thelowest leach percentage factor. Thus,the iron leach factor was transferred tothe following metals for which a zeroleach factor was previously used:aluminum, antimony, beryllium,selenium, silver, thallium, tin, andtitanium.

E. Non-Water Quality EnvironmentalImpact Analyses

As mentioned in Section III.E, EPAreceived additional informationregarding waste disposal practices ineach of the three geographic areas (e.g.,GOM, Offshore California, Cook Inlet,Alaska). As a result of this information,EPA revised the modeling for thefraction of waste either injected at thedrill site, injected on-shore or landdisposed (see SBF DevelopmentDocument). Though the percentage ofwaste injected onsite versus hauled toshore (20% vs. 80%) in the GOMremains unchanged, the method ofonshore disposal has been revised forthe final rule. In the GOM, 80% of thewaste hauled to shore is injectedonshore and only 20% is landfarmed.

EPA estimates that all SBF wastesfrom Californian deep water exploratorywells are sent onshore (i.e., 100%onshore disposal vs. 0% on-siteinjection). For all other wells (i.e.,shallow water development andexploratory and deep waterdevelopment), EPA estimates that mostof the offshore waste is disposedthrough offshore on-site cuttings re-injection (i.e., 20% onshore disposal vs.80% on-site injection) based on the factthat most of these wells are being drilledfrom fixed facilities. EPA estimates thatmost California offshore wastes sentonshore are disposed via onshoreformation injection (i.e., 20% of offshorewastes sent onshore disposed vialandfarming vs. 80% of offshore wastessent onshore disposed via onshoreinjection) based on the number ofCalifornia land disposal operations.

At proposal, based on the record forthe 1996 Coastal rule, EPA determinedthat onsite injection was not feasiblethroughout Cook Inlet, Alaska (seeCoastal Development Document, EPA–821–R–96–023, Section 5.10.3). Morerecently, however, EPA identified in theApril 2000 NODA (65 FR 21558) thatthe SBF rule record now demonstratesthat many Cook Inlet operators in

Coastal waters are using cuttings re-injection (see Docket No. W–98–26:Record No. III.B.a.11, Record No.III.B.a.23, Record No. III.B.a.53). EPAcontacted Cook Inlet operators (e.g.,Phillips, Unocal, Marathon Oil) and theState regulatory agency, Alaska Oil andGas Conservation Commission(AOGCC), for more information on themost recent re-injection practices ofCoastal and Offshore Cook Inletoperators (65 FR 21558). AOGCCregulations provide Cook Inlet operatorsthe opportunity to permit and operateClass II disposal wells and annulardisposal activities. Informationprovided to EPA indicate that Cook Inletoperators in Coastal waters are availingthemselves of on-site cuttings injectionand are receiving AOGCC permits forthis activity. Generally, Cook Inletoperators in Coastal waters agree thaton-site injection is available for mostoperations.

AOGCC also agreed that there shouldbe enough formation re-injectiondisposal capacity for the small numberof wells (< 5–10 wells per year) beingdrilled in Cook Inlet Coastal waters.AOGCC stated, however, that case-specific limitations should beconsidered when evaluating disposaloptions. For instance, Unocal hasexperienced difficulty establishingformation injection in several wells thatwere initially considered for annulardisposal. In addition, Cook Inletoperators have the burden of proving toAOGCC’s satisfaction that the waste willbe confined to the formation disposalinterval. Approval of annular disposalincludes a review of cementing andleak-off test records. In some instancesthe operator may also have to run acement bond log. When an older well isconverted for use as a disposal well,some of this information may not exist.In cases where there is insufficientinformation, disposal is not allowed.Annular disposal is also limited to thefacility on which the waste is generated.Although Class II disposal regulationsdon’t restrict waste transport, it hasgenerally been the practice of thevarious fields’ owners not to accept anywaste generated by other operators. Inaddition, AOGCC stated that a zerodischarge requirement poses serioustechnical hurdles with respect to thehandling of drilling waste forexploration drilling with mobile rigs.Normally, there is neither capacity forstorage or room for processingequipment on exploratory drilling rigs.Therefore, to be conservative for theNWQI analysis, EPA estimates that all ofthe cuttings from the Coastal Cook Inletoperations (i.e., shallow water wells) are

re-injected (i.e., 0% onshore disposal vs.100% on-site injection) based on theability of industry to dispose of oil-based cuttings via on-site formationinjection after gaining State regulatoryapproval.

In order to assess the SBF NWQIsrelative to the total impacts fromdrilling operations, EPA includedestimates of the daily drilling rigimpacts to the NWQIs from SBF-relatedactivities. The additional impactsconsist of fuel use and air emissionsresulting from the various drilling rigpumps and motors as well as impacts ofa daily helicopter trip for transportingpersonnel and/or supplies. Impactswere assessed for the number of daysthat an SBF interval is drilled versus thenumber of days well intervals aredrilled using WBFs and OBFs and forthe number of wells drilled using eachof the drilling fluids.

F. Numerical Limits for Retention of SBFBase Fluid on SBF-Cuttings

A series of potential numerical limitsfor retention of SBF base fluid on SBF-cuttings were developed based in parton combinations of data selectioncriteria suggested in comments on theApril 2000 NODA. These data selectioncriteria include: (1) Existing record ofretention calculations (i.e., ‘‘back-up’’retort sheet information for qualityassurance/quality control purposes);and (2) foreign or domestic location ofwell drilling activity (e.g., North Sea,Canada). Numerical limits promulgatedin today’s final rule were based on datawith existing records of retentioncalculations, and they included datafrom well drilling activities in foreigncountries. The inclusion of data fromforeign countries is intended to includedata representing drilling with cuttingsdryers at a wider range of geologicalformations than just the ones for whichdata was received from currentoperations.

V. Development and Selection ofEffluent Limitations Guidelines andStandards

A. Waste Generation andCharacterization

Drill cuttings are producedcontinuously at the bottom of the holeat a rate dependent on a variety offactors including: (1) The advancementof the drill bit; (2) the size and designof drill bit used (e.g., polycrystallinediamond compact (PDC)); and (3) thedrilling fluid type used. Drill cuttingsare carried to the surface by the drillingfluid, where the cuttings are separatedfrom the drilling fluid by the solidscontrol system. The drilling fluid is then



sent back to the active mud system (e.g.,mud pumps, down hole, trip tanks,etc.), provided it still has characteristicsto meet technical requirements. Drillingfluids cool and lubricate the drill bit,stabilize the walls of the borehole,transport cuttings, and maintainequilibrium between the borehole andthe formation pressures. Various sizes ofdrill cuttings are separated by the solidsseparations equipment, and it isnecessary to remove the fines (i.e., smallsized cuttings or ‘‘low gravity solids’’) aswell as the large cuttings from thedrilling fluid to maintain the requiredrheological properties.

Increased recovery from the cuttingsis more problematic for WBF than forSBF because the WBF water-wets thecuttings which encourages the cuttingsto disperse and spoil the drilling fluidproperties. Therefore, compared toWBF, more aggressive methods ofrecovering SBF from the cuttingswastestream are practical.

SBFs, used or unused, are a valuablecommodity and not a waste. It isindustry practice to continuously reusethe SBF while drilling a well interval,and at the end of the well, to ship theremaining SBF back to shore forrefurbishment and reuse. One of themain incentives for operators to attemptto recover as much SBF as possibleduring drilling is the relatively high unitcost of SBF, approximately $160 to $300per barrel, as compared to OBFs ($70 to90 per barrel) and WBFs ($45 per barrel)(Docket No. W–98–26, Record No.IV.B.a.13). Operators involved in thefirst 1998 GOM field demonstrations ofcuttings dryers (i.e., advanced solidscontrol technology) were attempting toobtain further reductions in drillingcosts, beyond that obtained byshortening the overall drilling time forthe well, by recovering more SBF. SBFsare relatively easy to separate from thedrill cuttings because the drill cuttingsdo not disperse or hydrate in thedrilling fluid to the same extent ascompared to WBFs. Reducing cuttingshydration is particularly important incertain formations (e.g., shaleformations in GOM). With WBF, due todispersion of the drill cuttings, drillingfluid components often need to beadded to maintain the required drillingfluid properties. These additions areoften in excess of what the drillingsystem can accommodate. The excess‘‘dilution volume’’ of WBF is a resultantwaste. This dilution volume waste doesnot occur with SBF. For these reasons,SBF is only discharged as a contaminantof the drill cuttings wastestream. It isnot discharged on purpose as neatdrilling fluid (i.e., drilling fluid notassociated with cuttings).

Current practice is that the top wellsection is normally drilled with a WBF.As the well becomes deeper, theperformance requirements of thedrilling fluid increase, and the operatormay, at some point, decide that thedrilling fluid system should be changedto either a traditional OBF, based ondiesel oil or mineral oil, or an SBF. Thesystem, including the drill string andthe solids separation equipment, mustbe changed entirely from the WBF to theSBF (or OBF) system, and the two donot function as a blended system. Theentire system is either: (1) A waterdispersible (aqueous) drilling fluid suchas a WBF; or (2) an oleaginous drillingfluid such as OBFs, enhanced mineraloil based drilling fluids, or SBFs. Thedecision to change the system from aWBF water dispersible system to anoleaginous drilling fluid depends onmany factors including:

I. The operational considerations (e.g.,rig type, risk of riser disconnects, rigequipment, and distance from supportfacilities);

II. The relative drilling performance ofone type fluid compared to another (e.g.,rate of penetration, well angle, holesize/casing program options, compatibledrilling bit, and horizontal deviation);

III. The presence of geologicconditions that favor a particular fluidtype or performance characteristic (e.g.,formation stability/sensitivity,formation pore pressure vs. fracturegradient, and potential for gas hydrateformation);

IV. Drilling fluid cost (i.e., base costplus daily operating cost);

V. drilling operation cost (i.e., rig costplus logistic and operation support);and

VI. Drilling waste disposal cost.Industry has commented that while

the right combination of factors thatfavor the use of SBF can occur in anyarea, they most frequently occur with‘‘deep water’’ operations (i.e., greaterthan or equal to 1,000 feet of water).This is due to the fact that theseoperations are higher cost and cantherefore better justify the higher initialcost of SBF use. Industry has alsocommented that SBF may beincreasingly used in shallow waterwells due to the ability of SBF toincrease average rates of penetration andshorten average times to completedrilling operations (Docket No. W–98–26, Record No. IV.A.a.3).

The volume of cuttings generatedwhile drilling the SBF or OBF intervalsof a well depends on the type of well(development or production) and thewater depth (shallow or deep). EPAdeveloped OBF and SBF model wellcharacteristics from information

provided by the American PetroleumInstitute (API). API provided well sizedate for four types of wells currentlydrilling the GOM: development andexploratory wells in both deep water(i.e., greater than or equal to 1,000 feetof water) and shallow water (i.e., lessthan 1,000 feet of water). These modelwells are referred to as: (1) Shallow-water development (SWD); (2) shallow-water exploratory (SWE); (3) deep-waterdevelopment (DWD); and (4) deep-waterexploratory (DWE). For the four modelwells, EPA determined that the volumesof cuttings generated by these SBF orOBF well intervals are (in barrels): 565for SWD; 1,184 for SWE; 855 for DWD;and 1,901 for DWE. These volumesrepresent only the rock, sand, and otherformation solids drilled from the hole,and do not include drilling fluid thatadheres to these formation cuttings.These values also include the additionalformation cuttings volume of 7.5%washout. Washout is caving in orsloughing off of the well bore. Washout,therefore, increases hole volume andincreases the amount of cuttingsgenerated when drilling a well. Thewashout percentage EPA used in itsanalyses (i.e., 7.5%) is based on the ruleof thumb reported by industryrepresentatives of 5 to 10% washoutwhen drilling with SBF or OBF.

Drilling fluid returning from the wellis laden with drill cuttings. The drillcuttings range in size from largeparticles which are on the order of acentimeter or more in size to smallparticles (i.e., fines or ‘‘low gravitysolids’’) which are fractions of amillimeter in size. Standard or currentpractice solids control systems employprimary and secondary shale shakers inseries with a ‘‘fines removal unit’’ (e.g.,decanting centrifuge or mud cleaner).The drilling fluid and drill cuttings fromthe well are first passed throughprimary shale shakers. These shakersremove the largest cuttings which areapproximately 1 to 5 millimeters in size.The drilling fluid recovered from theprimary shakers is then passed oversecondary shale shakers to removesmaller drill cuttings. Finally, a portionor all of the drilling fluid recoveredfrom the primary and secondary shakersmay be passed through the finesremoval unit to remove fines from thedrilling fluid. It is important to removefines from the drilling fluid in order tomaintain the desired rheologicalproperties of the active drilling fluidsystem (e.g., viscosity, density). Thus,the cuttings wastestream normallyconsists of discharged cuttings from theprimary and secondary shale shakersand fines from the fines removal unit.



Operators using improved solidscontrol technology process the cuttingsdiscarded from the primary andsecondary shale shakers through a‘‘cuttings dryer’’ (e.g., vertical orhorizontal centrifuge, squeeze pressmud recovery unit, High-G linearshaker). The cuttings from the cuttingsdryer are discharged and the recoveredSBF is sent to the fines removal unit.The advantage of the cuttings dryer isthat more SBF is recovered for re-useand less SBF is discharged into theocean. This, consequently, will reducethe pollutant loadings to the ocean andthe potential of the waste to causeanoxia (lack of oxygen) in the receivingsediment.

As discussed in the April 2000 NODA(65 FR 21569), solids control equipmentgenerally breaks larger particles intosmaller particles. An undesirableincrease in drilling fluid weight andviscosity can occur when drill solidsdegrade into fines and ultra-fines. Ultra-fines are generally classified as beingless than 5 microns (10–6 meters) inlength and solids control equipmentgenerally cannot remove these ultra-fines. An unacceptable high finescontent (i.e., generally > 5% of totaldrilling fluid weight) may consequentlylead to drilling problems (e.g.,undesirable rheological properties,stuck pipe). Therefore, it is possible thatthe increased recovery of SBF fromcuttings for re-use in the active mudsystem, often achieved through use ofthe cuttings dryer in solids controlsystems, may lead to a build-up in finesfor certain formation characteristics(e.g., high reactivity of formationcuttings, limited loss of drilling fluidinto the formation). In the April 2000NODA, EPA solicited commentsregarding whether EPA’s proposednumeric cuttings retention value mightcause operators (where there areunfavorable formation characteristics)to: (1) Dilute the fines in the active mudsystem through the addition of ‘‘fresh’’SBF; and/or (2) capture a portion of thefines in a container and send the finesto shore for disposal.

Comments from API/NOIA identifiedonly one instance in which the use ofa cuttings dryer in combination with afines removal unit in the United Statesmay have lead to an increase in ‘‘finesbuild-up’’ and a loss of circulation event(Docket No. W–98–26, Record No.IV.A.a.13). Further communication withadditional industry stakeholdersidentified that this well (Shell, GreenCanyon 69, OCS–G–13159#3) was thefirst application of the cuttings dryertype (horizontal centrifuge cuttingsdryer) in the GOM and inexperiencewith this type of technology may have

contributed to the build-up of finescausing well problems. However, othercommentors stated that fines build-upwas not an issue for the well in question(Docket No. W–98–26, Record No.IV.A.b.1). Moreover, further industrycomments revealed that the propertiesof formations are often the main culpritof loss circulation and that the same rig(Marianas) had a loss of circulation atanother nearby well in the sameformation when a cuttings dryer was notbeing used (Docket No. W–98–26,Record No. IV.A.b.1). Therefore, basedon the record, which includes over threedozen successful cuttings dryerdeployments, EPA concludes that finesbuild up is not an issue of concernwhen operators properly operate andmaintain cuttings dryers and finesremoval equipment.

Drill cuttings are typically dischargedcontinuously as they are separated fromthe drilling fluid in the solids separationequipment. The drill cuttings will alsocarry a residual amount of adhereddrilling fluid. Therefore, the twoparameters that make up the bulk of thepollutant loadings are TSS and what ismeasured by the API Retort Method(Appendix 7) as Total Oil. TSS iscomprised of two components: the drillcuttings themselves and the solids inthe adhered drilling fluid. The drillcuttings are primarily small bits ofstone, clay, shale, and sand. The sourceof the solids in the drilling fluid isprimarily the barite weighting agent,and clays (e.g., amine clays) which areadded for filtration control and tomodify the rheological properties.Benthic smothering and/or sedimentgrain size alteration resulting inpotential damage to invertebratepopulations and alterations in benthiccommunity structure is a concern withuncontrolled SBF drilling dischargesdue to the quantity and characteristicsof associated TSS discharges. In general,large cuttings particles with a highpercentage of adhering SBF (e.g., >12%(wt. SBF)/(wt. wet cuttings)) tend toconglomerate and quickly settle out tothe benthic environment quickly nearthe well site.

Additionally, environmental impactscan be caused by toxic, conventional,and non-conventional pollutantsadhering to the solids. The adhered SBFdrilling fluid is mainly composed, on avolumetric basis, of the syntheticmaterial (i.e., ‘‘base fluid’’). Formationoil can also contaminate SBF-cuttingsand contribute priority, conventional,and non-conventional pollutants. Theoleaginous material (i.e., SBF base fluidand formation oil) may be toxic and itmay contain priority pollutants such aspolynuclear aromatic hydrocarbons

(PAHs). Depending on bottom currents,temperature, and rate of biodegradationthis oleaginous material may causehypoxia (i.e., reduction in dissolvedoxygen concentrations) or anoxia (i.e.,absence of dissolved oxygen) in theimmediate sediment. Oleaginousmaterials which biodegrade quickly willreduce dissolved oxygen concentrationsmore rapidly than more slowlydegrading oleaginous materials. EPA,however, thinks that fast biodegradationis environmentally preferable to slowerbiodegradation despite the increasedrisk of temporary hypoxia whichaccompanies fast biodegradation. EPA’sposition is supported by publishedseabed surveys which show that benthicre-colonization by infaunal individualsafter the discharge of SBF-cuttings orOBF-cuttings can be correlated with thedisappearance of the base fluid in thesediment. Large persistent cuttings pilesmay provide a source of environmentalcontamination for many years (DocketNo. W–98–26, Record No. IV.F.2).Moreover, benthic re-colonization ratesdo not seem to be correlated with theseverity of any hypoxic or anoxic effectsthat may result while the SBF base fluidis degrading or dispersing. Numerousstudies show that SBF base fluids thatbiodegrade faster lead to a more rapidrecovery of the pre-discharge benthiccommunity.

As a component of the drilling fluid,the barite weighting agent is alsodischarged as a contaminant of the drillcuttings. Barite is a mineral principallycomposed of barium sulfate (BaSO4),and it is known to generally have tracecontaminants of several toxic heavymetals such as mercury, cadmium,arsenic, chromium, copper, lead, nickel,and zinc. SBF also contain non-conventional pollutants found in otherdrilling fluid components (e.g.,emulsifiers, oil wetting agents, filtrationcontrol agents, and viscosifiers).

As previously stated in the April 2000NODA (65 FR 21560), EPA learned thatSBF is controlled with zero dischargepractices at the drill floor, in the formof vacuums and sumps to retrievespilled fluid. EPA also learned thatapproximately 75 barrels of fine solidsand barite, which have an approximateSBF content of 25%, can accumulate inthe dead spaces of the mud pit, sandtrap, and other equipment in the drillingfluid circulation system. Currentpractice is to either wash these solidsout with water for overboard discharge,or to retain the waste solids for disposal.Several hundred barrels (approximately200 to 400 barrels) of water are used towash out the mud pits. Industryrepresentatives also indicated to EPAthat those oil and gas extraction



operations that discharge wash waterand accumulated solids first recover freeSBF.

B. Selection of Pollutant Parameters

1. Stock Limitations and Standards forBase Fluids

a. General. In the final rule, whereSBF-cuttings may be discharged, exceptfor Cook Inlet, Alaska, EPA isestablishing BAT limitations and NSPSthat require the synthetic materialswhich form the base fluid of the SBFsto meet limitations and standards onPAH content, sediment toxicity, andbiodegradation. If these stocklimitations are not met the technologybasis for meeting these limitations andstandards is: (1) Product substitution; or(2) zero discharge based on landdisposal or cuttings re-injection. Theregulated toxic, conventional, and non-conventional pollutant parameters areidentified below. A large range ofsynthetic, oleaginous, and watermiscible materials are available for useas base fluids. These stock limitationson the base fluid are intended toencourage product substitutionreflecting best available technology andbest available demonstrated technologywherein only those synthetic materialsand other base fluids which minimizepotential loadings and toxicity may bedischarged. Additionally, EPA isretaining BPT and BCT requirements forSBFs and SBF-cuttings as no dischargeof free oil as determined by the staticsheen text (Appendix 1 of subpart A of40 CFR Part 435).

As stated below in Section V.F, EPAis today promulgating BPT, BCT, BAT,and NSPS for SBFs and SBF-cuttings forCoastal Cook Inlet, Alaska as zerodischarge except when Coastal CookInlet, Alaska, operators are unable todispose of their SBF-cuttings using anyof the following disposal options: (1)On-site re-injection (annular disposal orClass II UIC); (2) re-injection using anearby Coastal or Offshore Class II UICdisposal well; or (3) onshore disposalusing a nearby Class II UIC disposalwell or land application. If an operatoris able to make these showings, then theoperator would be subject to the samerequirements for SBF-cuttings thatapply elsewhere. The regulated toxic,conventional, and non-conventionalpollutant parameters are identifiedbelow.

b. PAH Content. EPA is regulating thePAH content of base fluids becausePAHs are comprised of toxic prioritypollutants. SBF base fluids typically donot contain PAHs, whereas thetraditional OBF base fluids of diesel andmineral oil typically contain 5 to 10%

PAH and 0.35% PAH respectively. ThePAHs typically found in diesel andmineral oil include: (1) the toxic prioritypollutants fluorene, naphthalene,phenanthrene, and others; and (2) non-conventional pollutants such asalkylated benzenes and biphenyls.Therefore, the PAH BAT limitation andNSPS are components of this finalregulation to help discriminate betweenacceptable and non-acceptable basefluids.

c. Sediment Toxicity. EPA is alsoregulating the sediment toxicity in basefluids as a non-conventional pollutantparameter and as an indicator for toxicpollutants and non-conventionalpollutants in base fluids (e.g., enhancedmineral oils, internal olefins, linearalpha olefins, poly alpha olefins,paraffinic oils, C12–C14 vegetable estersof 2-hexanol and palm kernel oil, ‘‘lowviscosity’’ C8 esters, and otheroleaginous materials). It has beenshown, during EPA’s development ofthe Offshore Guidelines, thatestablishing limits on toxicityencourages the use of less toxic drillingfluids and additives. Many of the SBFbase fluids have been shown to havelower toxicity than OBF base fluids, butamong SBFs some are more toxic thanothers. Today’s final discharge option(i.e., BAT/NSPS Option 2) includes abase fluid sediment toxicity stocklimitation, as measured by the 10-daysediment toxicity test (ASTM E1367–92)using a natural sediment or formulatedsediment and Leptocheirus plumulosusas the test organism.

d. Biodegradation. EPA is alsoregulating the biodegradation in basefluids as an indicator of the extent, inlevel and duration, of the toxic effect oftoxic pollutants and non-conventionalpollutants present in the base fluids(e.g., enhanced mineral oils, internalolefins, linear alpha olefins, poly alphaolefins, paraffinic oils, C12–C14 vegetableesters of 2-hexanol and palm kernel oil,‘‘low viscosity’’ C8 esters, and otheroleaginous materials). Based on resultsfrom seabed surveys at sites wherevarious base fluids have beendischarged with drill cuttings, EPAbelieves that the results from the threebiodegradation tests used during therulemaking (i.e., solid phase test,anaerobic closed bottle biodegradationtest, respirometry biodegradation test)are indicative of the relative rates ofbiodegradation in the marineenvironment. In addition, EPA thinksthe biodegradation parameter correlatesstrongly with the rate of recovery of theseabed where OBF- and SBF-cuttingshave been discharged. The various basefluids vary widely in biodegradationrates, as measured by the three

biodegradation methods. However, therelative ranking of the base fluidsremain relatively similar across all threebiodegradation tests.

As originally proposed in February1999 (64 FR 5504) and re-stated in theApril 2000 NODA (65 FR 21550), EPAis today promulgating a BAT limitationand NSPS to control the minimumamount of biodegradation of base fluid.Today’s final discharge option (i.e.,BAT/NSPS Option 2) includes a basefluid biodegradation stock limitation, asmeasured by the marine anaerobicclosed bottle biodegradation test (i.e.,ISO 11734).

e. Bioaccumulation. EPA alsoconsidered establishing a BATlimitation and NSPS that would limitthe base fluid bioaccumulationpotential. The regulated parameterswould be the non-conventional andtoxic priority pollutants thatbioaccumulate. EPA reviewed thecurrent literature to identify thebioaccumulation potential of variousbase fluids. EPA determined that SBFsare not expected to significantlybioaccumulate because of theirextremely low water solubility andconsequent low bioavailability. Theirpropensity to biodegrade makes themfurther unlikely to significantlybioaccumulate in marine organisms.

EPA identified that hydrophobicchemicals (e.g., ester base fluids) thathave a log Kow less than about 3 to 3.5may bioaccumulate rapidly but not tohigh concentrations in tissues of marineorganisms, particularly if they arereadily biodegradable into non-toxicmetabolites (Docket No. W–98–26,Record No. IV.F.1). (Note: The octanol/water partition coefficient (Kow) is usedas a surrogate for estimating lipid/waterpartitioning). Moreover, hydrophobicchemicals (e.g., C16–C18 internal olefins,various poly alpha olefins, and C18 n-paraffins) with a log Kow greater thanabout 6.5 to 7 do not bioaccumulateeffectively from the water, because theirsolubility in both the water and lipidphases is very low (Docket No. W–98–26, Record No. IV.F.1). Finally, thedegradation by-products of SBF basefluids (e.g., alcohols) are likely to bemore polar (i.e., more miscible withwater) than the parent substances. Thehigher water solubility will result inthese degradation by-productspartitioning into the water column andbeing diluted to toxicologicallyinsignificant concentrations.

2. Discharge Limitationsa. Free Oil. Under BPT and BCT

limitations for SBF-cuttings, EPA retainsthe prohibition on the discharge of freeoil as determined by the static sheen test



(see Appendix 1 of subpart A of 40 CFRpart 435). Under this prohibition, drillcuttings may not be discharged whenthe associated drilling fluid would failthe static sheen test. The prohibition onthe discharge of free oil is intended tominimize the formation of sheens on thesurface of the receiving water. Theregulated parameter of the no free oillimitation would be the conventionalpollutant oil and grease which separatesfrom the SBF and causes a sheen on thesurface of the receiving water.

The free oil discharge prohibitiondoes not control the discharge of oil andgrease and crude oil contamination inSBFs as it would in WBFs. With WBFs,oils which may be present (e.g., dieseloil, mineral oil, formation oil, or otheroleaginous materials) are present as thediscontinuous phase. As such these oilsare free to rise to the surface of thereceiving water where they may appearas a film or sheen upon or discolorationof the surface. By contrast, theoleaginous matrices of SBFs do notdisperse in water. In addition they areweighted with barite, which causesthem to sink as a mass without releasingeither the oleaginous materials whichcomprise the SBF or any contaminantformation oil. Thus, the test would notidentify these pollutants. However, aportion of the SBF may rise to thesurface to cause a sheen. Thecomponents that rise to the surface fallunder the general category of oil andgrease and are considered conventionalpollutants. Therefore, the purpose of theno free oil limitation of today’s finalregulation is to control the discharge ofconventional pollutants which separatefrom the SBF and cause a sheen on thesurface of the receiving water. Thelimitation is not intended to controlformation oil contamination nor thetotal quantity of conventional pollutantsdischarged.

b. Formation Oil Contamination. Asoriginally proposed in February 1999(64 FR 5505) and re-stated in the April2000 NODA (65 FR 21552), EPA is todaypromulgating a BAT limitation andNSPS of zero discharge to controlformation oil contamination on SBF-cuttings. EPA is also today promulgatinga screening method (Reverse PhaseExtraction (RPE) method presented inAppendix 6 to subpart A of part 435)and a compliance assurance method(Gas Chromatograph/Mass Spectrometer(GC/MS) method presented in Appendix5 to subpart A of part 435).

Formation oil is an ‘‘indicator’’pollutant for the many toxic and prioritypollutant pollutants present information (crude) oil (e.g., aromatic andpolynuclear aromatic hydrocarbons).These pollutants include benzene,

toluene, ethylbenzene, naphthalene,phenanthrene, and phenol. EPA isrequiring that formation oilcontamination be measured at twopoints. First, EPA is requiring thatoperators verify and document that aSBF is free of formation oilcontamination before initial use of theSBF through use of the GC/MScompliance assurance method(Appendix 5 to subpart A of 40 CFR part435). Second, EPA is requiring thatoperators use the RPE method(Appendix 6 to subpart A of 40 CFR part435) for the SBF recovered by the solidscontrol equipment to detect formationoil contamination. The RPE method is afluorescence test and is appropriately‘‘weighted’’ to better detect crude oils.These crude oils contain more toxicaromatic and PAH pollutants and showbrighter fluorescence (i.e.,noncompliance) in the RPE method atlower levels of crude oil contamination.Since the RPE method is a relativebrightness test, operators may also usethe GC/MS compliance assurancemethod when the results from the RPEmethod are in doubt by either theoperator or the enforcement authority.Results from the GC/MS complianceassurance method will supersede thoseof the RPE method.

c. Retention of Drilling Fluid onCuttings. EPA is today promulgating aBAT limitation and NSPS to control theretention of drilling fluid on drillcuttings. The BAT limitation and NSPSare presented as the percentage of basefluid on wet cuttings (i.e., mass basefluid (g)/mass wet cuttings (g)), averagedover the entire well sections drilledwith SBF. The limitation and standardcontrols the quantity of drilling fluiddischarged with the drill cuttings. Bothtoxic pollutants and non-conventionalpollutants would be controlled by thislimitation. Several pollutants arepresent in the barite weighting agent,including the toxic metal pollutantsarsenic, chromium, copper, lead,mercury, nickel, and zinc, and the non-conventional metal pollutantsaluminum and tin. A complete SBFformulation also includes non-conventional pollutants found in theSBF base fluids (e.g., enhanced mineraloils, internal olefins, linear alphaolefins, poly alpha olefins, paraffinicoils, C12–C14 vegetable esters of 2-hexanol and palm kernel oil, ‘‘lowviscosity’’ C8 esters, and otheroleaginous materials) and in otherdrilling fluid components (e.g.,emulsifiers, oil wetting agents, filtrationcontrol agents, and viscosifiers). Thesepollutants would not be controlled bythe sediment toxicity stock limitations.

In response to the February 1999proposal (64 FR 5501), EPA receivedcomments that these non-conventionalpollutants include fatty acids (DocketNo. W–98–26, Record No. III.A.a.7).EPA also received further informationthat the non-conventional pollutants inthese drilling fluid components includeamine clays, amine lignites, and dimer/trimer fatty acids (Docket No. W–98–26,Record No. III.B.b.1).

This limitation would also control thetoxic effect of the drilling fluid and thepersistence or biodegradation of thebase fluid. Specifically, as stated in theApril 2000 NODA (65 FR 21553),lowering the percentage of residualdrilling fluid retained on cuttingsincreases the recovery rate of the seabedreceiving the cuttings (Docket No. W–98–26, Record No. I.D.b.30 and 31;Record No. III.B.a.15). Limiting theamount of SBF content in dischargedcuttings controls: (1) The amount oftoxic and non-conventional pollutantsin SBF which are discharged to theocean; (2) the biodegradation rate ofdischarged SBF; and (3) the potential forSBF-cuttings to develop cuttings pilesand mats which are deleterious to thebenthic environment.

As originally proposed in February1999 (64 FR 5547) and re-stated in theApril 2000 NODA (65 FR 21552), EPAis today promulgating a retort andsampling compliance method for thecuttings retention BAT limitation andNSPS (see Appendix 7 to subpart A of40 CFR part 435; API RecommendedPractice 13B–2).

d. Sediment Toxicity. EPA is alsoregulating the sediment toxicity in SBFdischarged with cuttings as a non-conventional pollutant parameter and asan indicator for toxic pollutants inSBFs. As originally proposed inFebruary 1999 (64 FR 5491) and re-stated in April 2000 (65 FR 21557), EPAis today promulgating a BAT limitationand NSPS to control the maximumsediment toxicity of the SBF dischargedwith cuttings at the point of discharge.The sediment toxicity of the SBF-cuttings at the point of discharge ismeasured by the modified sedimenttoxicity test (ASTM E1367–92) using anatural sediment or formulatedsediment and Leptocheirus plumulosusas the test organism.

EPA finds that the sediment toxicitytest at the point of discharge is practicalas an indicator of the sediment toxicityof the drilling fluid at the point ofdischarge. The sediment toxicity testapplied at the point of discharge willcontrol non-conventional pollutantsfound in some drilling fluidcomponents (e.g., emulsifiers, oilwetting agents, filtration control agents,



and viscosifiers) which are added to thebase fluid in order to build a completeSBF package. Other possible toxicpollutants in drilling fluids may includemercury, cadmium, arsenic, chromium,copper, lead, nickel, and zinc, andformation oil contaminants. Aspreviously stated, establishing dischargelimits on toxicity encourages the use ofless toxic drilling fluids and additives.The modifications to the 10-daysediment toxicity test includeshortening the test to 96-hours.Shortening the test will allow operatorsto continue drilling operations while thesediment toxicity test is beingconducted on the discharged drillingfluid. Moreover, discriminatory poweris substantially reduced for the 10-daytest on drilling fluid as compared to the96-hour test (i.e., the 10-day test is oflower practical use in determiningwhether a SBF is substantially differentfrom OBFs). Finally, operatorsdischarging WBFs are alreadycomplying with a biological test at thepoint of discharge, the 96-hour SPPtoxicity test, which tests whole WBFaquatic toxicity using the test organismMysidopsis bahia.

3. Maintenance of Current RequirementsToday’s rule does not modify the

existing BAT and NSPS limitations onthe stock barite of 1 mg/kg mercury and3 mg/kg cadmium. These limitationscontrol the levels of toxic pollutantmetals because cleaner barite that meetsthe mercury and cadmium limits is alsolikely to have reduced concentrations ofother metals. Evaluation of therelationship between cadmium andmercury and the trace metals in bariteshows a correlation between theconcentration of mercury with theconcentration of arsenic, chromium,copper, lead, molybdenum, sodium, tin,titanium and zinc (see Section VI,Offshore Development Document, EPA–821–R–93–003).

Today’s rule does not modify theexisting BAT and NSPS limitationsprohibiting the discharge of drillingwastes containing diesel oil in anyamount. Diesel oil is considered an‘‘indicator’’ for the control of specifictoxic pollutants. These pollutantsinclude benzene, toluene, ethylbenzene,naphthalene, phenanthrene, andphenol. Diesel oil may contain from 3 to10% by volume PAHs, which constitutethe more toxic pollutants in petroleumproducts.

Today’s rule does not modify theexisting BAT limitation and NSPS forcontrolling the maximum aqueousphase toxicity of SBF-cuttings at pointof discharge using the suspendedparticulate phase (SPP) test (see

Appendix 2 of subpart A of Part 435).The BAT limitation and NSPS forcontrolling aqueous toxicity ofdischarged SBF-cuttings is retained asthe minimum 96-hour LC50 of the SPPshall be 3% by volume. EPA isinterested in controlling the toxicity ofdrilling fluids in the sediment and thewater column and is requiring both asediment toxicity test and an aqueousphase toxicity test to assess overalltoxicity of the drilling fluid at the pointof discharge. EPA finds that the SPP testat the point of discharge is practical asa measurement of the aquatic toxicity ofthe drilling fluid at the point ofdischarge. The discharge SPP test willcontrol non-conventional pollutantsfound in drilling fluid components (e.g.,emulsifiers, oil wetting agents, filtrationcontrol agents, and viscosifiers) whichare added to the base fluid in order tobuild a complete SBF package.Moreover, operators discharging WBFsare already complying with the SPPtoxicity test on discharged WBFs.

C. Regulatory Options Considered andSelected for Drilling Fluid NotAssociated With Drill Cuttings

In the February 1999 proposal, EPAproposed BPT, BCT, BAT, and NSPS aszero discharge for SBFs not associatedwith drill cuttings. In the April 2000NODA, EPA published two options forthe final rule for the BAT limitation andNSPS for controlling SBFs notassociated with SBF drill cuttings: (1)Zero discharge; or (2) allowing operatorsto choose either zero discharge or analternative set of BMPs with anaccompanying compliance method.Industry supported the second optionstating that the first option (zerodischarge) would result in the costlyand potentially dangerous collection,shipping, and disposal of largequantities of rig site wash watercontaining only a small quantity of SBF(Docket No. W–98–26, Record No.IV.A.a.13). Industry also stated thatBMPs would be extremely effective atreducing the quantity of non-cuttingsrelated SBF and would focus operators’attention on reducing these discharges.

EPA is today promulgating BPT, BCT,BAT, and NSPS of zero discharge forSBFs not associated with drill cuttings.This wastestream consists of neat SBFsthat are intended for use in thedownhole drilling operations (e.g., drillbit lubrication and cooling, holestability). This wastestream istransferred from supply boats to thedrilling rig and can be released duringthese transfer operations. Thiswastestream is often spilled on the drilldeck but contained through gratedtroughs, vacuums, or squeegee systems.

This wastestream is also held innumerous tanks during all phases of thedrilling operation (e.g., trip tanks,storage tanks). EPA receivedinformation that rare occurrences ofimproper SBF transfer procedures (e.g.,no bunkering procedures in place for rigloading manifolds) and improperoperation of active mud systemequipment (e.g., no lock-out, tag-outprocedures in place for mud pit dumpvalves) has the potential for thedischarge of tens to hundreds of barrelsof neat SBF, or SBF not associated withcuttings, if containment is not practiced(Docket No. W–98–26, Record No.IV.A.a.26, QTECH LTD Reports forOcean America and Discoverer 534).

Current practice for control of SBF notassociated with drill cuttings is zerodischarge (e.g., drill deck containment,bunkering procedures), primarily due tothe value of SBFs recovered and reused.Therefore, zero discharge for SBF notassociated with drill cuttings istechnologically available andeconomically achievable. Moreover,these controls generally allow the re-useof SBF in the drilling operation and hasno unacceptable NWQIs.

EPA has also decided that solidsaccumulated at the end of the well(‘‘accumulated solids’’) and wash waterused to clean out accumulated solids oron the drill floor are associated withdrill cuttings and are therefore notcontrolled by the zero dischargerequirement for SBFs not associatedwith drill cuttings (see Section V.F.2.b).

D. BPT Technology Options Consideredand Selected for Drilling FluidAssociated With Drill Cuttings

EPA is today promulgating BPTeffluent limitations for the cuttingscontaminated with SBFs (‘‘SBF-cuttings’’). The BPT effluent limitationspromulgated today for SBF-cuttingswould control free oil as a conventionalpollutant. The BPT limitation is no freeoil as measured by the static sheen test,performed on SBF separated from thecuttings in U.S. Offshore waters andCoastal Cook Inlet, Alaska.

In setting the no free oil limitation inU.S. Offshore waters and Coastal CookInlet, Alaska, EPA considered the sheencharacteristics of currently availableSBFs. Since this requirement iscurrently met by dischargers in theGOM, EPA anticipates no additionalcosts to the industry to comply with thislimitation. Therefore, EPA believes thatthis limitation represents theappropriate level of control for SBFsassociated with drill cuttings.



E. BCT Technology Options Consideredand Selected for Drilling FluidAssociated With Drill Cuttings

In July 1986, EPA promulgated amethodology for establishing BCTeffluent limitations. EPA evaluates thereasonableness of BCT candidatetechnologies—those that aretechnologically feasible—by applying atwo part cost test: (1) A POTW test; and(2) an industry cost-effectiveness test.

EPA first calculates the cost perpound of conventional pollutantremoved by industrial dischargers inupgrading from BPT to a BCT candidatetechnology and then compares this costto the cost per pound of conventionalpollutants removed in upgradingPOTWs from secondary treatment. Theupgrade cost to industry must be lessthan the POTW benchmark of $0.25 perpound (in 1976 dollars). In the industrycost-effectiveness test, the ratio of theincremental BPT to BCT cost divided bythe BPT cost for the industry must beless than 1.29 (i.e., the cost increasemust be less than 29%).

The BCT effluent limitationspromulgated today would control freeoil as a conventional pollutant. EPA istoday promulgating a BCT effluentlimitation for SBF-cuttings of no free oilequivalent to the BPT limitation forSBF-cuttings of no free oil asdetermined by the static sheen test inU.S. Offshore waters and Coastal CookInlet, Alaska.

In developing BCT limits for the U.S.Offshore waters and Coastal Cook Inlet,Alaska, EPA considered whether thereare technologies (including drillingfluid formulations) that achieve greaterremovals of conventional pollutantsthan promulgated for BPT, and whetherthose technologies are cost-reasonableaccording to the BCT Cost Test. EPAidentified no technologies that canachieve greater removals ofconventional pollutants as comparedwith the U.S. Offshore waters andCoastal Cook Inlet BPT requirementsthat are also cost-reasonable under theBCT Cost Test. Accordingly EPA istoday promulgating BCT effluentlimitations for SBF-cuttings equal to thepromulgated BPT effluent limitationsfor SBF-cuttings in U.S. Offshore watersand Coastal Cook Inlet, Alaska.

F. BAT Technology Options Consideredand Selected for Drilling FluidAssociated With Drill Cuttings

EPA is promulgating stock limitationsand discharge limitations in a two partapproach to control SBF-cuttingsdischarges under BAT. The first part isbased on product substitution throughuse of stock limitations (e.g., sediment

toxicity, biodegradation, PAH content,metals content) and dischargelimitations (e.g., diesel oil prohibition,formation oil prohibition, sedimenttoxicity, aqueous toxicity). The secondpart is the control of the quantity of SBFdischarged with SBF-cuttings. Aspreviously stated in the April 2000NODA, EPA finds that the second partis particularly important becauselimiting the amount of SBF content indischarged cuttings controls: (1) Theamount of SBF discharged to the ocean;(2) the biodegradation rate of dischargedSBF; and (3) the potential for SBF-cuttings to develop cuttings piles andmats which are detrimental to thebenthic environment.

EPA is also today retaining theexisting BAT limitations on: (1) Thestock barite of 1 mg/kg mercury and 3mg/kg cadmium; (2) the maximumaqueous toxicity of discharged SBF-cuttings as the minimum 96-hour LC50

of the Suspended Particulate Phasetoxicity test (SPP) shall be 3% byvolume; and (3) prohibiting thedischarge of drilling wastes containingdiesel oil in any amount. Theselimitations control the levels of toxicmetal and aromatic pollutantsrespectively. EPA at this time thinksthat all of these components areessential for appropriate control of SBF-cuttings discharges.

The BAT effluent limitationspromulgated today for SBF-cuttingswould control a variety of toxic andnon-conventional pollutants in the stockbase fluids by controlling their PAHcontent, sediment toxicity, andbiodegradation. The BAT effluentlimitations promulgated today for SBF-cuttings would also control a variety oftoxic and non-conventional pollutantsat the point of discharge by controllingformation oil contamination, sedimenttoxicity, and the quantity of SBFdischarged. The BAT stock anddischarge limitations are describedbelow.

The BAT level of control in the U.S.Offshore waters has been developedtaking into consideration among otherthings: (1) The availability, cost, andenvironmental performance of SBF basefluids in terms of PAH content,sediment toxicity, and biodegradationrate; (2) the availability, cost, andenvironmental performance of SBFsretained on the cuttings discharge interms of sediment toxicity andbiodegradation rate; (3) the frequency offormation oil contamination at thevarious control levels for the discharges;(4) the availability, cost, andenvironmental performance ofequipment and methods to recover SBFfrom the drill cuttings being discharged;

and (5) the NWQIs of each option. Byenvironmental performance, EPA meansboth a reduction in the quantity ofpollutants discharged to the ocean anda reduction in their environmentaleffects in terms of sediment toxicity,aquatic toxicity, and biodegradationrate. Issues related to the technicalavailability and economic achievabilityof today’s promulgated BAT limitationsare discussed below by regulatedparameter. The NWQIs of each selectedoption is discussed in Section VIIIbelow. EPA also considered NWQIs inselecting the controlled dischargeoption for SBF-cuttings (i.e., BAT/NSPSOption 2) (see Section VIII).

EPA and industry sediment toxicityand biodegradation laboratory studiesshow that both vegetable esters and lowviscosity esters have betterenvironmental performance than allother SBF base fluids. EPA, however,rejected the option of basing BATsediment toxicity and biodegradationstock limitations and NSPS solely onvegetable esters and low viscosity estersbecause the record does not indicatethat these fluids can be used in drillingsituations throughout the offshoresubcategory nor could EPA predict theconditions and circumstances wherethese fluids would be able to be used(see Section V.F.1.a). EPA is sufficientlysatisfied, however, that both estersprovide better environmentalperformance (e.g., sediment toxicity,biodegradation). Consequently, EPA ispromulgating an alternative higherretention on cuttings (ROC) BATdischarge limitation to encourage theuse of esters. The higher ROC dischargelimitation for SBFs complying with thestock limitations based on esters isderived from data representing fourcuttings dryer technologies (e.g., verticalcentrifuge, horizontal centrifuge,squeeze press mud recovery unit, andHigh-G linear shaker). The lower ROCBAT discharge limitation for the SBFscomplying with the C16–C18 internalolefin stock limitations is based on datafrom the two top performing cuttingsdryer technologies (e.g., verticalcentrifuge and horizontal centrifuge).EPA data demonstrates that operatorsproperly using these cuttings dryertechnologies (e.g., vertical centrifuge,horizontal centrifuge, squeeze press,High-G linear shaker) will be able tocomply with the final higher ROCnumerical limitation for ester-basedSBFs. EPA believes that this balancingof the importance of retention valueswith environmental performance asreflected by sediment toxicity andbiodegradation rates is justified becauseof the greater ability of esters to



biodegrade and of their lower sedimenttoxicity.

Therefore, EPA balanced theenvironmental performance of the basefluid (in terms of sediment toxicity andbiodegradation) with the environmentalperformance of cuttings associated withdrilling fluids (in terms of the retentionon cuttings limit) to determine theappropriate best available technology.EPA determined that the improvedtoxicity and biodegradation of the esterbased fluids justified increasedflexibility in the ROC limitation as longas the limitation reflected the use ofcuttings dryers technologies.

EPA, however, did not base the higherROC BAT discharge limitation for esterson current shale shaker technologybecause this does not represent the bestavailable technology (or best availabledemonstrated technology). EPA does notbelieve that the improvedenvironmental performance of estersjustifies the huge difference in pollutantloadings between existing shale shakertechnology and newer cuttings dryertechnology. Because the effluentlimitations and standards promulgatedin this rule account for variability, theeffluent limitation and standards arehigher than the long term average uponwhich the technology is based. Here, theLTA for the esters ROC limitation of9.4% is 4.8%; while the LTA for the IOsROC limitation of 6.9% is 3.82%. Bycontrast, the LTA for existing shaleshaker technology is 10.2%. Thisdifference translates to 118 millionpounds per year of pollutants beingdischarged using the existing and newmodel well counts for the selected BAToption (i.e., BAT/NSPS Option 2) (seeSBF Development Document). Further,as previously stated in the April 2000NODA (65 FR 21553), field results showthat: (1) Cuttings are dispersed duringtransit to the seabed and no cuttingspiles are formed when SBFconcentrations on cuttings are heldbelow 5%; and (2) cuttings dischargedfrom cuttings dryers (with SBF retentionvalues under 5%) in combination witha sea water flush, hydrate very quicklyand disperse like water-based cuttings.Thus, while EPA is willing to provideadditional flexibility to dischargers ofester-based fluids, EPA believes that theappropriate technology basis thatreflects BAT is cuttings dryerstechnology.

EPA determined that zero dischargefor BAT was technically feasible andeconomically achievable because priorto the use of SBFs, the industry was ableto operate using only the traditionalOBFs (based on diesel oil and mineraloil), which are prohibited fromdischarge. EPA concluded that a zero

discharge BAT limitation for SBF-cuttings would decrease the use of SBFsin favor of OBFs and WBFs. This isbecause a zero discharge BAT limitationfor SBF-cuttings would create anincentive for operators to use the leastexpensive drilling fluids (i.e., OBFs,WBFs) in order to minimize overallcompliance costs.

EPA rejected the BAT zero dischargeoption for SBF-cuttings wastes becauseit would result in unacceptableincreases in NWQIs. Therefore, EPArejected the zero discharge option forSBF-cuttings wastes in U.S. waters inthe Offshore subcategory of 40 CFR part435 (‘‘U.S. Offshore waters’’). Aspreviously stated in Section II.B, use ofOBFs in place of SBFs would lead to anincrease in NWQIs including thetoxicity of the drilling waste. Use ofWBFs in place of SBFs would generallylead to a per well increase in pollutantsdischarged, an increase in NWQIs, andan increase in aquatic toxicity. WBFdrilling operations lead to per wellincreases in pollutants dischargedbecause WBFs generate six times morewashout (e.g., sloughing) of the wellwall than SBFs. Also, WBF drillingoperations lead to increases in NWQIsbecause WBF drilling operationsgenerally take longer than SBF drillingoperations which lead to more airemissions and fuel usage from drillingrigs and equipment. Aquatic toxicitygenerally increases when drilling fluidmanufacturers add supplements (e.g.,glycols, shale inhibitors) to WBFs forthe purpose of making WBFs havetechnical capabilities (e.g., lubricity,shale suppression) similar to SBFs. EPAestimates that, under the zero dischargeoption, some operators would switch toWBF compositions with more nonaqueous drilling fluid properties (e.g.,lubricity, shale suppression), and thatthese WBFs would exhibit greateraquatic toxicity.

EPA’s analyses show that under theSBF-cuttings zero discharge option ascompared to current practice, for U.S.Offshore waters existing sources, therewould be an increase of 35 millionpounds of cuttings annually shipped toshore for disposal in non-hazardousoilfield waste (NOW) sites and anincrease of 166 million pounds ofcuttings annually injected. In addition,under the SBF-cuttings zero dischargeoption, operators would use the moretoxic OBFs. The zero discharge optionfor SBF-cuttings would lead to anincrease in annual fuel usage of 358,664BOE and an increase in annual airemissions of 5,602 tons. Finally, theSBF-cuttings zero discharge option inthe U.S. Offshore waters would lead toan increase of 51 million pounds of

WBF cuttings being discharged to U.S.Offshore waters. This pollutant loadingincrease is a result of GOM operatorsswitching from efficient SBF drilling toless efficient WBF drilling.

EPA’s analysis shows that the impactsof adequately controlled SBF dischargesto the water column and benthicenvironment are of limited scope andduration. By contrast, the landfilling ofOBF-cuttings is of a longer termduration and associated pollutants mayaffect ambient air, soil, and groundwaterquality. EPA and DOE documented atleast five CERCLA (or ‘‘Superfund’’)sites in Louisiana and Californiacontaminated with oilfield wastes andmore than a dozen other sites subject toFederal or State cleanup actions.

Nonetheless, while SBF-cuttingsdischarge with adequate controls ispreferred over zero discharge in U.S.Offshore waters, SBF-cuttings dischargewith inadequate controls is notpreferred over zero discharge. EPAbelieves that to allow discharge of SBF-cuttings in U.S. Offshore waters, theremust be appropriate controls to ensurethat EPA’s discharge limitations reflectthe ‘‘best available technology’’ or otherappropriate level of technology. EPAhas worked with industry to address theappropriate determination of PAHcontent, sediment toxicity,biodegradation, quantity of SBFdischarged, and formation oilcontamination that are technicallyavailable, economically achievable, andhave acceptable NWQIs. The final BATlimitations are a result of this effort andare discussed below.

EPA is today promulgating BAT ofzero discharge for SBF-cuttings forCoastal Cook Inlet, Alaska except whenCoastal Cook Inlet, Alaska, operators areunable to dispose of their SBF-cuttingsusing any of the following disposaloptions: (1) On-site re-injection (annulardisposal or Class II UIC); (2) re-injectionusing a nearby Coastal or Offshore ClassII UIC disposal well; or (3) onshoredisposal using a nearby Class II UICdisposal well or land application.Coastal Cook Inlet, Alaska, operators arerequired to demonstrate to the NPDESpermit controlling authority that none ofthe above three disposal options aretechnically feasible in order to qualifyfor the alternate BAT limitation. CoastalCook Inlet, Alaska, operators thatqualify for the alternate BAT limitationare allowed to discharge SBF-cuttings atthe same level of BAT control asoperators in Offshore waters. TheNPDES permit controlling authority willuse the procedure given in Appendix 1to subpart D of 40 CFR part 435 toestablish whether or not a Coastal CookInlet, Alaska, operator qualifies for the



SBF-cuttings zero discharge exemption.As stated in Appendix 1 to subpart D of40 CFR part 435, the following factorsare considered in the determination ofwhether or not Coastal Cook Inlet,Alaska, operators qualify for the SBF-cuttings zero discharge exemption: (1)Inability to establish formation injectionin wells that were initially consideredfor annular or dedicated disposal; (2)inability to prove to UIC controllingauthority that the waste will be confinedto the formation disposal interval; (3)inability to transport drilling waste to anoffshore Class II UIC disposal well or anonshore disposal site; and (4) whetheror not there is no available land disposalfacilities (e.g., onshore re-injection, landdisposal).

EPA finds that this option istechnically available and economicallyachievable. Operators are currentlybarred from discharging OBFs, SBFs,and enhanced mineral oil based drillingfluids under the Cook Inlet NPDESgeneral permit (64 FR 11889). Aspreviously discussed in Section IV.E,EPA identified that many Cook Inletoperators in Coastal waters are usingcuttings re-injection to comply withzero discharge disposal requirements forOBFs and OBF-cuttings. EPA contactedCook Inlet operators (e.g., Phillips,Unocal, Marathon Oil) and the Stateregulatory agency, AOGCC, for moreinformation on the most recent re-injection practices of Coastal andOffshore Cook Inlet operators. AOGCCstated that there should be enoughformation re-injection disposal capacityfor the small number of non-aqueousdrilling fluid wells (<5–10 wells peryear) being drilled in Cook Inlet Coastalwaters. Therefore, since Coastal CookInlet operators are already complyingwith zero discharge of OBF- and SBF-cuttings, this option is economicallyachievable as there are no incrementalcompliance costs.

AOGCC stated, however, that casespecific limitations should beconsidered when evaluating disposaloptions (see Section IV.E). Cook Inlet,Alaska, operators may experience thefollowing difficulties in attempting tocomply with a zero dischargerequirement for SBFs: (1) Inability toestablish formation injection in wellsthat were initially considered forannular or dedicated Class II UICdisposal; (2) inability to prove toAOGCC’s satisfaction that the waste willbe confined to the formation disposalinterval; and (3) inability to transportdrilling waste to an offshore Class II UICdisposal well or an onshore disposalsite. EPA believes that while theseproblems are currently not presented bydrilling in Cook Inlet, they could be a

problem in the future. Further, EPAbelieves this to be a greater problem inCook Inlet where climate, tides, and itsdistance from commercial disposal sitesmake transportation to shore lessfeasible than in other offshore watersnear the continental U.S. If EPA did notprovide for some exceptions within theguideline itself, and these problemspresented themselves beyond the timeframe for requesting a FundamentallyDifferent Factors variance (undersection 301(n)(2) of the CWA, 180 days)this would render zero discharge notachievable. Therefore, EPA believes it isreasonable to provide for someflexibility to the current practice of zerodischarge in Cook Inlet.

EPA further finds the NWQIs of thisoption for Cook Inlet to be acceptable.As previously stated, few non-aqueousdrilling fluid wells are drilled in CoastalCook Inlet, Alaska (<5–10 wells peryear). EPA finds that the small numberof wells drilled per year (even if all ofthem are drilled using SBF) leads tovery small increases in NWQIs. Tables6 though 10 describe the annual airemissions and fuel usage for the threegeographic regions including Cook Inlet,Alaska. In particular, a zero dischargerequirement for SBFs and SBF-cuttingsin Cook Inlet, Alaska, would lead to anannual increase of 94 tons of airemissions and 6,067 BOE fuel used forexisting sources. EPA does notanticipate and new sources in CookInlet, Alaska. Consequently, EPA findsthat the overall small increases inNWQIs from the zero discharge option,as compared to either of the two SBF-cuttings discharge options, in CoastalCook Inlet, Alaska, are acceptable. Thetwo SBF-cuttings discharge optionsshow little change in NWQIs ascompared to baseline (see Tables 6though 9).

1. Stock Base Fluid TechnicalAvailability and EconomicAchievability

a. Introduction. As SBFs havedeveloped over the past few years, theindustry has come to use mainly alimited number of primary base fluids.These include the internal olefins,linear alpha olefins, poly alpha olefins,paraffinic oils, C12–C14 vegetable estersof 2-hexanol and palm kernel oil, and‘‘low viscosity’’ C8 esters. These fluidsrepresent virtually all the SBFscurrently used in oil and gas extractionindustry. EPA collected data onperformance, environmental impact,and costs for these SBFs to develop theeffluent limitations for today’s finalrule. The following definitions are usedin this preamble to describe variousSBFs: (1) Internal olefin (IO) refers to a

series of isomeric forms of C16 and C18

alkenes; (2) linear alpha olefin (LAO)refers to a series of isomeric forms of C14

and C16 monoenes; (3) poly alpha olefin(PAO) refers to a mix mainly comprisedof a hydrogenated decene dimer C20H62

(95%), with lesser amounts of C30H62

(4.8%) and C10H22 (0.2%); (4) vegetableester refers to a monoester of 2-ethylhexanol and saturated fatty acidswith chain lengths in the range C8–C16;and (5) ‘‘low viscosity’’ ester refers to anester of natural or synthetic C8 fattyacids and alcohols. EPA also has data onother SBF base fluids, such as enhancedmineral oil, paraffinic oils (i.e.,saturated hydrocarbons or ‘‘alkanes’’),and the traditional OBF base fluids:mineral oil and diesel oil.

The stock base fluid limitations intoday’s rule are based on the technologyof product substitution. Thepromulgated limitations are technicallyavailable because they are based oncurrently available base fluids that canbe used in the wide variety of drillingsituations in U.S. offshore waters. EPAanticipates that the base fluids meetingall requirements would includevegetable esters, low viscosity esters,and internal olefins. In addition, basedon current information, EPA believesthat the stock base fluid controls onPAH content, sediment toxicity, andbiodegradation rate being promulgatedtoday are sufficient to only allow thedischarge of only those base fluids (e.g.,esters, internal olefins) with lowerbioaccumulation potentials (i.e., log Kow

<3 to 3.5 and log Kow> 6.5 to 7).Therefore, EPA found it wasunnecessary to promulgate a separatelimitation for bioaccumulation.

As previously stated in April 2000 (65FR 21554), EPA considered basing thesediment toxicity and biodegradationstock limitations and standards solelyon vegetable esters (i.e., original esters)instead of the proposed C16–C18 IO. EPAalso considered subcategorizing thefinal rule to determine when vegetableesters are not practical and when C16–C18 IOs could be used instead. EPAconsidered these options due to thepotential for better environmentalperformance of vegetable ester-baseddrilling fluids. EPA and industryanalytical testing show that esters havebetter sediment toxicity andbiodegradation performance.

EPA rejected the option of basingsediment toxicity and biodegradationstock limitations and standards onvegetable esters due to several technicallimitations. These technical limitationsof vegetable esters preclude their use inall areas of the GOM, OffshoreCalifornia, and Cook Inlet, Alaska.Vegetable ester technical limitations



include: (1) High viscosity comparedwith other IO SBFs at all temperatures,with an increasing difference astemperature decreases, leading to lowerrates of penetration in wells and greaterprobability of losses due to higherequivalent circulating densities; (2) highgel strength in risers that develops whena vegetable ester-based SBF is notcirculated; (3) a high temperaturestability limit ranging from about 225 °Fto perhaps 320 °F—the exact valuedepends on the detailed chemistry ofthe vegetable ester (i.e., the acid, thealcohol) and the drilling fluidchemistry; (4) reduction of the thermalstability limit through hydrolysis whenvegetable esters are in contact withhighly basic materials (e.g., lime, greencement) at elevated temperatures; and(5) less tolerance of the muds tocontamination by seawater, cement, anddrill solids than is observed for IO–SBFs(Docket No. W–98–26: Record No.IV.A.a.3, Attachment A2—‘‘Limitationsof Esters’; Record No. IV.A.a.13,Attachments Ester-51, 52, 53, 54, 56).

EPA also rejected the option ofsubcategorizing the use of esters todefine drilling conditions when onlyesters could be allowed for a controlleddischarge. EPA could not establish a‘‘bright line’’ rationale to define thesituation where only esters should bethe benchmark fluid (i.e., only esterswould be allowed for a controlleddischarge). EPA considered many of theengineering factors used for selection ofa drilling fluid (e.g., rig size andequipment; formation characteristics;water depth and environment; lubricity,rheological, and thixotropicrequirements) and determined that thistype of sub-categorization was notpossible. EPA, however, is encouragingthe use of esters by promulgating ahigher ROC limitation and standardwhen esters are used.

EPA also considered basing sedimenttoxicity and biodegradation stocklimitations and standards on lowviscosity esters. Comments to the April2000 NODA state that laboratoryanalyses, which were designed tosimulate GOM conditions to which afluid may be exposed, indicate that lowviscosity esters have the followingtechnical properties: (1) Similar orbetter viscosity than C16–C18 IOs; (2) canbe used to formulate stable low viscosityester-based SBFs up to 300 °F; (3) canbe used to formulate low viscosity ester-based SBFs to 16.0+ lbs/gal mud weight;(4) can reduce oil/water ratios to 70/30,thus reducing volumes of base fluiddischarged; (5) high tolerance to drilledsolids; (6) flat gels make it easier tobreak circulation, minimizing initialcirculation pressures and subsequent

risk of fracture; (7) high tolerance toseawater contamination; and (8)rheological properties can be adjustedby use of additives to suit specificconditions (Docket No. W–98–26,Record No. IV.A.a.7). EPA also receivedinformation on one well section drilledwith low viscosity esters. Some of theresults from this low viscosity ester wellsection were compared to the resultsfrom another well section in the samelocation where C16–C18 IOs were used.These results show that the lowviscosity ester had: (1) Comparable orbetter equivalent circulating densities(i.e., acceptable fluid properties); and (2)faster ROP through better hole cleaningand higher lubricity (i.e., fewer daysrequired to drill to total depth whichlead to less NWQI and overall drillingcosts). The low viscosity esters arerelatively new base fluids and have onlyrecently been available to the market.Despite the results from the laboratoryanalyses and one well section, EPA doesnot believe that this is enoughinformation to make the determinationthat low viscosity esters can be used inall or nearly all drilling conditions inthe offshore U.S. waters (e.g., differingformations, water depths, andtemperatures). Therefore, EPA rejectedthe option of basing sediment toxicityand biodegradation stock limitationsand standards on low viscosity esters.EPA is sufficiently satisfied, however,that low viscosity esters and vegetableesters provide better environmentalperformance (e.g., sediment toxicity,biodegradation). Consequently, EPA ispromulgating higher retention oncuttings discharge limitations whereesters are used to encourage operators touse esters when possible.

b. PAH Content TechnicalAvailability. Today’s promulgatedlimitation of PAH content for U.S.Offshore waters is a weight ratio definedas the weight of PAH (as phenanthrene)per weight of the stock base fluidsample. The PAH weight ratio is0.001%, or 10 parts per million (ppm).This limitation is based on theavailability of base fluids that are free ofPAHs and the detection of the PAHs byEPA Method 1654A, ‘‘PAH Content ofOil by High Performance LiquidChromatography with a UV Detector.’’Method 1654A was published inMethods for the Determination ofDiesel, Mineral and Crude Oils inOffshore Oil and Gas IndustryDischarges (EPA–821–R–92–008,incorporated by reference and availablefrom National Technical InformationService at (703) 605–6000). As originallyproposed in February 1999 (64 FR5503), EPA is promulgating the use of

the EPA Method 1654A for compliancewith this PAH content BAT limitation.

EPA’s promulgated PAH contentlimitation is technically available.Producers of several SBF base fluidshave reported to EPA that their basefluids are free of PAHs. The base fluidswhich suppliers have reported are freeof PAHs include IOs, LAOs, vegetableesters, low viscosity esters, certainenhanced mineral oils, syntheticparaffins, certain non-syntheticparaffins, and others. The use of thesefluids can accommodate the broadvarieties of drilling situations faced byindustry in offshore U.S. waters (seeSBF Development Document, ChapterIV). Compliance with the stock BATlimitation and NSPS on PAH contentwill be achieved by productsubstitution.

c. Sediment Toxicity TechnicalAvailability. EPA is today promulgatinga sediment toxicity stock base fluidlimitation that would only allow thedischarge of SBF-cuttings using SBFbase fluids as toxic or less toxic, but notmore toxic, than C16–C18 IOs.Alternatively, this limitation could beexpressed in terms of a ‘‘sedimenttoxicity ratio’’ which is defined as 10-day LC50 of C16–C18 internal olefinsdivided by the 10-day LC50 of stock basefluid being tested. EPA is promulgatinga sediment toxicity ratio of less than 1.0.Compliance with this limitation isdetermined by the 10-day Leptocheirusplumulosus sediment toxicity test (i.e.,ASTM E1367–92: ‘‘Standard Guide forConducting 10-day Static SedimentToxicity Tests With Marine andEstuarine Amphipods’ (incorporated byreference and available from ASTM, 100Bar Harbor Drive, West Conshohocken,PA 19428), supplemented with thepreparation procedure specified inAppendix 3 of Subpart A of 40 CFR part435). As originally proposed in February1999 (64 FR 5503) and re-stated in April2000 (65 FR 21549), EPA ispromulgating the use of the ASTME1367–92 method for compliance withthis sediment toxicity BAT limitation.

Since the February 1999 proposal,EPA and other researchers conductednumerous 10-day L. plumulosussediment toxicity tests on various SBFbase fluids with natural and formulatedsediments. Nearly all the SBF basefluids have lower sediment toxicity thandiesel and mineral oil. Some SBF basefluids, however, show greater sedimenttoxicity than other SBF base fluids (see65 FR 21550; Docket No. W–98–26,Record No. IV.A.a.13). The base fluidsmeeting this limitation includevegetable esters, low viscosity esters,internal olefins, and some PAOs (see 65



FR 21550; Docket No. W–98–26, RecordNo. IV.A.a.13).

EPA finds this limit to be technicallyavailable and economically achievablethrough product substitution becauseinformation in the rulemaking recordsupports the findings that vegetableesters, low viscosity esters, and internalolefins have performance characteristicsenabling them to be used in the widevariety of drilling situations in offshoreU.S. waters and meet today’spromulgated limit.

EPA selected the C16–C18 IO, which isthe most popular drilling fluid in theGOM, as the basis for the sedimenttoxicity rate ratio limitation instead ofthe vegetable ester or low viscosity esterfor several reasons: (1) EPA does notbelieve that vegetable esters can be usedin all drilling situations; and (2) EPAdoes not have sufficient field testinginformation that low viscosity esters canbe used in all drilling situations (seeSection V.F.1.a). In addition, because ofthe uncertainty about ester performance,operators may not be encouraged toswitch from OBFs or WBFs to SBF whenproperly installed and maintained.Specifically, vendor supplied dataassociated with these cuttings dryerdeployments suggest that the overallcuttings dryer downtime (i.e., timewhen cuttings dryer equipment is notoperable) is approximately 1 to 2%(Docket No. W–98–26, Record No.IV.A.a.6). EPA finds this smalldowntime percentage as acceptable.

EPA discussed how it revised theBAT/NSPS-level solids controlequipment configuration used in itsanalyses in the April 2000 NODA (65 FR21559). EPA also discussed a range ofmanagement options regarding the BATlimitation for SBF retention on SBF-cuttings: (1) Two discharges from theBAT/NSPS-level solids controlequipment configuration (i.e., onedischarge from the cuttings dryer andanother discharge from the finesremoval unit); (2) one discharge fromthe BAT/NSPS-level solids controlequipment configuration (i.e., onedischarge from the cuttings dryer withthe fines from the fines removal unitcaptured for zero discharge); and (3)zero discharge of SBF-cuttings. Thesethree options are labeled as BAT/NSPSOption 1, BAT/NSPS Option 2, andBAT/NSPS Option 3, respectively. EPAestimates that 97% and 3% of the totalcuttings are generated by cuttings dryerand fines removal unit, respectively.

EPA developed two numerical wellaveraged ROC limitations (i.e., one forSBFs with the stock base fluidperformance similar to esters andanother for SBFs with the stock basefluid performance similar to C16–C18

internal olefins) and based both of theseROC limitations on the technology ofonly one discharge from the cuttingsdryer with the fines from the finesremoval unit captured for zero discharge(i.e., BAT/NSPS Option 2). Thenumerical well averaged ROC maximumlimitation for SBFs (i.e., 9.4%) with theenvironmental characteristics of estersis based on a combination of data fromhorizontal centrifuge, verticalcentrifuge, squeeze press, and High–Glinear shaker cuttings dryertechnologies. The numerical wellaveraged ROC maximum limitation forSBFs (i.e., 6.9%) with theenvironmental characteristics of C16–C18

internal olefins is based on acombination of data from horizontal andvertical centrifuge cuttings dryertechnologies. EPA estimates thatoperators, generally installing newequipment where none has been used inthe past, will be able to choose fromamong the better technologies, designs,operating procedures, and maintenanceprocedures that EPA has considered tobe among the best availabletechnologies. EPA data demonstratesthat operators properly using thesecuttings dryer technologies will be ableto comply with these final ROCnumerical limitations. Data submitted toEPA show that operators using thevertical centrifuge and horizontalcentrifuge are capable of achieving thelower ROC limitation (i.e., 6.9%). Datasubmitted to EPA also show thatoperators using the vertical centrifuge,horizontal centrifuge, squeeze press,and High-G linear shaker are capable ofachieving the higher ROC limitation(i.e., 9.4%). More details on theobserved performance of the individualtechnologies and details of calculationfor the numerical limits are presented inthe SBF Statistical Support Documentand SBF Development Document.

EPA developed the two ROClimitations because EPA used a two partapproach to control SBF-cuttingsdischarges. The first part is the controlof which SBF are allowed for dischargethrough use of stock limitations (e.g.,sediment toxicity, biodegradation, PAHcontent, metals content) and dischargelimitations (e.g., diesel oil prohibition,formation oil prohibition, sedimenttoxicity, aqueous toxicity). The secondpart is the control of the quantity of SBFdischarged with SBF-cuttings. Aspreviously stated, EPA and industrysediment toxicity and biodegradationlaboratory studies show that bothvegetable esters and low viscosity estershave better environmental performancethan all other SBF base fluids. However,because the technical availability of

product substitution with esters was notdemonstrated across the offshoresubcategory, EPA rejected the option ofbasing sediment toxicity andbiodegradation stock limitations andstandards on vegetable esters and lowviscosity esters (see V.F.1.a). EPA issufficiently satisfied, however, that bothesters provide better environmentalperformance (e.g., sediment toxicity,biodegradation). Consequently, EPA ispromulgating a higher retention oncuttings discharge limitation toencourage operators to use esters whenpossible. EPA estimates that a higherretention on cuttings dischargelimitation for esters is equivalent to thesame level of control as a lowerretention on cuttings dischargelimitation for all other SBFs that havepoorer sediment toxicity andbiodegradation performances.

In response to the April 2000 NODA,EPA received comments from an ester-based SBF manufacturer that EPAshould create an incentive for operatorsto use ester-based SBFs by basing theROC limitation for ester-based SBFs onbaseline solids control equipment (e.g.,primary and secondary shale shakers,fines removal unit) (Docket No. W–98–26, Record No. IV.A.a.7). In latecomments, this same commentorclaimed that a ROC limitation based onany cuttings dryer technology would notprovide any incentive for the use ofester-based SBFs (Docket No. W–98–26,Record No. IV.A.a.38). Further, theyargued that the superior laboratoryperformance of these ester base fluids interms of sediment toxicity andbiodegradation justifies allowing themto be discharged with a ROC limitationbased on baseline solids controlequipment. EPA estimates that a ROCBAT limitation based on the baselinesolids control equipment is above15.3%.

While EPA is willing to expand thetechnology basis to allow the use of lesseffective cuttings dryers for ester-basedSBFs (e.g., squeeze press, High-G linearshakes), EPA is unwilling to entirelyabandon the use of cuttings dryers forester-based SBF drilling operations. EPAis unwilling to set a higher ROClimitation for SBFs with theenvironmental performance of ester-based SBFs based on baseline solidscontrol technology because theenvironmental improvement resultingfrom the use of improved solids controltechnology (i.e., cuttings dryers)outweighs the incremental esterlaboratory sediment toxicity andbiodegradation performance overinternal olefins. Cuttings dryers promotepollution prevention through increasedre-use of drilling fluids and prevent



significant amounts of pollutants frombeing discharged to the ocean.

EPA provides for variability from thelong term average (LTA) of performancedata from the candidate treatmenttechnology or technologies. The LTAperformance of the baseline solidscontrol technology is 10.2%, ascompared to the LTA of 4.8% based ondata from all four cutting dryertechnologies. This difference translatesto 118 million pounds per year ofpollutants being discharged using theexisting and new model well counts forthe selected BAT option (i.e., BAT/NSPS Option 2) (see SBF DevelopmentDocument). Further, as previouslystated in the April 2000 NODA (65 FR21553), field results show that: (1)Cuttings are dispersed during transit tothe seabed and no cuttings piles areformed when SBF concentrations oncuttings are held below 5%; and (2)cuttings discharged from cuttings dryers(with SBF retention values under 5%) incombination with a sea water flush,hydrate very quickly and disperse likewater-based cuttings. Thus, while EPAis willing to provide additionalflexibility to dischargers of ester-basedfluids, EPA believes that the appropriatetechnology basis that reflects BAT iscuttings dryers technology. In balancingthe environmental effects of theseadditional ester-based SBFs dischargescontrolled with the use of baselinesolids control technology against theenvironmental effects of lower internalolefin-based SBFs discharges controlledwith the use of cuttings dryers, EPA hasconcluded that the improvement insolids control technology leading tolower values of ROC is a moresignificant factor than laboratory datafor ester base fluids showing lowersediment toxicity and higherbiodegradation.

EPA is also not convinced that thedifference in ROC limitations providesno incentive to use ester-based SBFs, asthe ester-based SBF manufacturerargues. EPA believes that the differencebetween 6.9% and 9.4% could providean incentive for operators to use ester-based SBFs. As operators haveincreasingly installed cuttings dryers inthe GOM (over three dozen successfuldeployments in the last two years), andas any SBF discharger installs newtechnology to comply with the lowerROC limitation (i.e., 6.9%), operatorsmay find that it is worthwhile topurchase ester-based SBFs in order to beable to operate with even a greatermargin of flexibility under a limit of9.4% as compared to 6.9%.

As this rule is performance based,EPA is not prohibiting the discharge ofSBF-cuttings from the fines removal

unit in order to comply with the basefluid retained on cuttings dischargeBAT limitation. Operators are onlyrequired to show that the volumeweighted average of all their SBF-cuttings discharges is below thedischarge BAT limitation. EPA expectsthat most operators will be able todischarge cuttings from the cuttingsdryer and fines removal unit andcomply with this discharge BATlimitation. If, for example, the averageretention of SBF on SBF-cuttings from acuttings dryer is 6.00%, the averageretention of SBF on SBF-cuttings from afines removal unit is 12.00%, and thefines are observed to comprise 3% of thetotal cuttings discharged, then the wellaverage is 6.18% (i.e., (0.97) (6.00%) +(0.03)(12.00%) = 6.18%). If the wellaverage for SBF retention from thecuttings dryer exceeds the dischargelimit then in order to comply with thisdischarge BAT limitation all cuttingsmust be re-injected on-site or hauled toshore for land disposal. EPA finds thatif this is the case, the limit istechnologically available becauseoperators have transported OBFs toshore since 1986 and have transportedWBFs that do not meet the existingeffluent limitations and standards since1993.

EPA finds that both ROC limitations(i.e., 6.9%, 9.4%) are technicallyavailable to the industry because theyare based on product substitution and astatistical analysis of ROC performancefrom drilling conditions throughoutoffshore waters. The BAT limitations forcontrolling the amount of SBFdischarged with SBF-cuttings arecalculated such that nearly all wellaverages for retention are expected tomeet these values using the selectedtechnologies without any additionalattention to design, operation, ormaintenance. EPA data demonstratesthat operators properly using thesecuttings dryer technologies will be ableto comply with these final ROCnumerical limitations because: (1) Theselimits allow for variation in formationcharacteristics that may not exist in theUnited States; (2) operators, generallyinstalling new equipment where nonehas been used in the past, will be ableto choose from among the bettertechnologies, designs, operatingprocedures, and maintenanceprocedures that EPA considers to beamong the best available technologies;and (3) operators may elect to use SBFswith the stock base fluid performance ofesters and horizontal or verticalcentrifuge cuttings dryers to achieve aROC well average well below the 9.4%ROC limitation.

Data used in the calculation of thenumerical limits exclude retentionresults submitted without backupcalculations (i.e., without raw retortdata) and include data from drillingoperations in foreign waters (e.g.,Canada). EPA excluded ROC datawithout raw retort data (e.g., masses andvolumes of cuttings samples andrecovered liquids taken during the retortmethod by the field technician) due toconcerns over data quality (e.g., noindependent method to check dataquality). EPA included ROC data fromCanadian drilling operations toincorporate the variability of cuttingsdryer performance in harder and lesspermeable formations that generallylead to higher ROC values. EPAestimates that the major factors leadingto higher ROC values for all solidscontrol equipment include: (1) Slowerrates of penetration; (2) formations thatare harder and less permeable; and (3)selection of certain drill bits. TheCanadian ROC data come fromformations that are generally muchharder and less permeable than what isobserved in the GOM. These harderformations generally lead to slower ratesof penetration. The less permeableCanadian formations lead to fewerdownhole losses of SBF. Downholelosses require the addition of fresh SBFto maintain volume requirements for theactive mud system. These additions offresh SBF to the active mud system helpcontrol the potential of build-up offines. In addition, operators often usePDC drill bits in order to grind throughthe hard Canadian formations. Thisgrinding action leads to smaller cuttingsthan is what is observed in the GOM.The smaller cuttings have more surfacearea for SBF than larger cuttings andgenerally have higher ROC values.Consequently, EPA’s use of Canadiandata in its analyses incorporatesufficient variability to model theformations in GOM, Offshore California,Cook Inlet, Alaska, and other offshoreU.S waters where EPA does not haveROC data.

EPA finds that both well-averagedischarge BAT ROC limitations (e.g.,6.9%, 9.4%) for base fluid on wetcuttings are economically achievable.According to EPA’s analysis, in additionto reducing the discharge of SBFsassociated with the cuttings, EPAestimates that this control will result ina net savings of $48.9 million ($1999)dollars per year. This savings results, inpart, because the value of the SBFrecovered is greater than the cost ofinstallation of the improved solidscontrol technology.

EPA concluded that a zero dischargerequirement for SBF-cuttings from



existing sources and the subsequentincrease use of OBFs and WBFs wouldresult in: (1) Unacceptable NWQIs; and(2) more pollutant loadings to the oceandue to operators switching from SBFs toless efficient WBFs (see Sections II.Band V.F). For these reasons, EPArejected the BAT zero discharge optionfor SBF-cuttings from existing sources.

EPA also requested comments in theApril 2000 NODA (65 FR 21570) on theissue of rig compatibility with theinstallation of cuttings dryers (e.g.,vertical or horizontal centrifuges,squeeze press mud recovery units, High-G linear shakers). EPA received generalinformation on the problems and issuesrelated to cuttings dryer installationsfrom API/NOIA stating that not all rigsare capable of installing cuttings dryers(Docket No. W–98–26, Record No.IV.A.a.13). In late comments, someindustry commentors asserted that 48 ofthe 223 GOM drilling rigs are notcapable of having a cuttings dryersystem installed due to either rig spaceand/or rig design without prohibitivecosts or rig modifications (Docket No.W–98–26, Record No. IV.B.b.33). Upona further, more extensive review ofGOM rigs, these same commentorsasserted that 30 of 234 GOM drilling rigsare not capable of having a cuttingsdryer system installed due to either rigspace and/or rig design withoutprohibitive costs or rig modifications(Docket No. W–98–26, Record No.IV.B.b.34). EPA also received latecomments from one operator, Unocal,stating that 36 of 122 Unocal wellsdrilled between late 1997 and mid-2000were drilled with rigs that do not have40 foot × 40 foot space available whichthey assert is necessary for a cuttingsdryer installation (Docket No. W–98–26,Record No. IV.B.b.31). The API/NOIArig survey and the Unocal rig surveyidentified most of the same rigs asunable to install cuttings dryers.However, two rigs (i.e., Parker 22,Nabors 802) identified in the Unocal rigsurvey as having no space for a cuttingsdryer installation were identified in theAPI/NOIA rig survey as each having aprevious cuttings dryer installation.Unocal requested in late comments thatEPA subcategorize certain rigs frombeing subject to the retention limit orthat these rigs be able to discharge SBFsusing performance that reflects currentshale shaker technology (Docket No. W–98–26, Record No. IV.A.a.36).

Based on the record, EPA finds thatcurrent space limitations for cuttingsdryers do not require a 40 foot × 40 footspace. Specifically, EPA has in therecord information gathered duringEPA’s October 1999 site visit andinformation supplied by API/NOIA,

MMS, and equipment vendors. EPAreceived information from a drillingfluid manufacturer and cuttings dryerequipment vendor, M-I Drilling Fluids,stating that they are not aware of anyGOM rig not capable of installing acuttings dryer (Docket No. W–98–26,Record No. IV.B.b.32). Another cuttingsdryer equipment vendor, JB Equipment,asserted that there are at most only afew rigs that pose questionableinstallation problems and that they haveyet to survey a rig that they could notinstall a cuttings dryer (Docket No. W–98–26, Record No. IV.B.b.48). JBEquipment also stated that inexperiencewith cuttings dryer installations mayinhibit the ability of operators or rigowners to properly judge whether acuttings dryer can be installed. JBEquipment cited an example where theoperator concluded that a cuttings dryercould not be installed on a rig (Nabors803) while JB Equipment surveyingefforts identified the cuttings dryerinstallation for the same rig as one of thesimplest installations JB Equipmentperforms. MMS also concluded that rigsdo not need a 40 foot × 40 foot spaceto install a cuttings dryer and that, withthe exception of a few jackup andplatform rigs, there should not be anysignificant issues related to installingcuttings dryers on OCS drilling rigs(Docket No. W–98–26, Record No.IV.B.a.28). API/NOIA estimated that 150square feet are required for a cuttingsdryer installation in order to meet theROC BAT limitation and NSPS (DocketNo. W–98–26, Record No. IV.A.a.13).EPA also estimates that the minimumheight clearance for a typical cuttingsdryer installation is 6 feet (see SBFDevelopment Document). The API/NOIA estimate is based on theinstallation of a horizontal centrifugecuttings dryer (i.e., MUD–6). TheUnocal estimate is based on the verticalcentrifuge cuttings dryer and is alsocharacterized by other industryrepresentatives and MMS as too high(Docket No. W–98–26, Record No.IV.B.b.34; Record No. IV.B.a.28). EPA’sestimate of a typical vertical centrifugeinstallation is 15 feet × 15 feet (i.e., 225square feet) with a minimum heightclearance of 11 feet (see SBFDevelopment Document). EPA based theROC BAT limitation and NSPS (e.g.,6.9%) on the use of both these cuttingsdryers for SBFs with the stocklimitations of C16–C18 IOs. Based oncomments from operators, equipmentvendors, and MMS, EPA believes thatmost of these shallow water rigs havethe requisite 150–225 square feetavailable to install a cuttings dryer (seeSBF Development Document).

Therefore, EPA finds that operators arenot required to have a 1,600 square footspace for a cuttings dryer installation inorder to meet the ROC BAT limitationand NSPS. Proper spacing andplacement of cuttings dryers in thesolids control equipment system shouldprevent installation problems.

Because of the large discrepancybetween EPA’s record information andthe space requirements asserted by thecommenter (1,600 square feet versusEPA’s 225 square feet + 11 feet in heightfor the vertical centrifuge or 150 squarefeet + 6 feet in height for the horizontalcentrifuge—MUD–6), EPA does notnecessarily believe that there are asmany wells that cannot install cuttingsdryers as the commentor (Unocal)claims. Further, based on scant detailsupporting these assertions, and theirlateness in the process, EPA has nobasis upon which to assess them orverify them.

Moreover, EPA does not believe thatit has enough information to reasonablysubcategorize these facilities, nor did ithave time to provide public notice ofhow it would define such a subcategory,given the court-ordered deadline for thisrule. EPA does not believe that basinga subcategory by specifying a spacerequirement alone (e.g. operators that donot have a certain amount of deck spaceavailable on, below or adjacent to thedeck would not be subject to thisrequirement) would be sufficient toprevent operators from configuring theirother equipment in a manner that wouldenable them to fit into the subcategory.Such an exception might also lead tooperators to make other assertionsjustifying that they should be included(e.g., that while they have a certainamount of space available, safetyreasons prevent placement of thetechnology on the rig). Without asolution to these issues, EPA isconcerned that such a subcategorizationwould potentially be too broad and beunworkable.

For these reasons, EPA believes thatthe appropriate way to handle theseconcerns is through the fundamentallydifferent factors (FDF) variance process.This process, provided for under CWAsection 301(n), would allow operators tosubmit supporting data and informationto EPA and would give the public theopportunity to comment on that data todetermine whether an FDF is trulywarranted for that drilling facility. EPAhas authority over owners andoperators, who are both dischargers, butthe NPDES regulations require theoperator to apply for the NPDES permit:‘‘When a facility or activity is owned byone person but is operated by anotherperson, it is the operator’s duty to obtain



a permit,’’ (see 40 CFR 122.21(b)). Thus,mobile drill rig ‘‘operators’’ asdischargers can apply for FDFs (see 40CFR 125.32; 122.21(b)).

EPA notes that the ROC limitationsand standards do not preclude the useof SBFs if an operator cannot meet themif the operator can meet zero dischargethrough re-injection or shipment toshore. Historically, dischargers haveused water-based fluids in shallowwater wells and this may also be anoption. EPA considers controlled WBFdischarges preferable to uncontrolledSBF discharges. EPA examined theNWQIs associated with these zerodischarge operations as acceptable (seeSBF Development Document). TheNWQIs of zero discharge for the shallowwater wells are much smaller that thoseassociated for the entire region coveredby this rule. Further, while a SBF-cuttings discharge option with adequatecontrols is preferred over the zerodischarge option for SBF-cuttings inU.S. Offshore waters, a SBF-cuttingsdischarge option with inadequatecontrols is not preferred over zerodischarge. The retention limit is a veryimportant control because it controls:(1) The amount of SBF discharged to theocean; (2) the biodegradation rate ofdischarged SBF; and (3) the potential forSBF-cuttings to develop cuttings pilesand mats which are detrimental to thebenthic environment. In short, EPA doesnot view existing shale shakertechnology (or performance of othertechnology equivalent to shale shakertechnology) to constitute theappropriate level of control under BATor BADT (NSPS).

EPA has also decided that solidsaccumulated at the end of the well(‘‘accumulated solids’’) and wash waterused to clean out accumulated solids oron the drill floor are associated withdrill cuttings and are therefore notcontrolled by the zero dischargerequirement for SBFs not associatedwith drill cuttings (see Section V.C).EPA has decided to control accumulatedsolids and wash water under thedischarge requirements for cuttingsassociated with SBFs. The amount ofSBF base fluid discharged withdischarged accumulated solids will beestimated using procedures inAppendix 7 to subpart A of 40 CFR part435 and incorporated into the base fluidretained on cuttings numeric limitationor standard. The source of the pollutantsin the accumulated solids andassociated wash water are drill cuttingsand drilling fluid solids (e.g., barite).The drill cuttings and drilling fluidsolids can be prevented from dischargewith SBF-cuttings due to equipmentdesign (e.g., sand traps, sumps) or

improper maintenance of the equipment(e.g., failing to ensure the properagitation of mud pits). EPA agrees withcommentors that the discharge of SBFassociated with accumulated solids inthe SBF active mud system and theassociated wash water is normally aone-time operation performed at thecompletion of the SBF well (e.g.,cleaning out mud pits and solids controlequipment).

The quantity of SBF typicallydischarged with accumulated solids andwash water is relatively small. The SBFfraction in the 75 barrels of accumulatedsolids is approximately 25% andgenerally only very small quantities ofSBF are contained in the 200 to 400barrels of associated equipment washwater. Current practice is to retainaccumulated solids for zero discharge orrecover free oil from accumulated solidsprior to discharge. Since currentpractice is to recover free oil anddischarge accumulated solids, thecontrolled discharge option for SBF-cuttings represents current practice andis economically achievable. Moreover,recovering free oil from accumulatedsolids prior to discharge has nounacceptable NWQIs. EPA definesaccumulated solids and wash water asassociated with drill cuttings. Therefore,operators will control these SBF-cuttings wastes using the SBF stocklimitations and cuttings dischargelimitations. As compliance with EPA’sSBF stock limitations and cuttingsdischarge limitations does not requirethe processing of all SBF-cuttingswastes through the solids controltechnologies (e.g., shale shakers,cuttings dryers, fines removal units),operators may or may not elect toprocess accumulated solids or washwater through the solids controltechnologies.

EPA is also promulgating a set ofBMPs for operators to use thatdemonstrates compliance with thenumeric ROC limitation and thereforereduces the retort monitoring otherwiserequired to determine compliance withthe numeric ROC limitation. This optioncombines the set of BMPs that representcurrent practice with BMPs that areassociated with the use of improvedsolids control technology. This option istechnologically available andeconomically achievable for the samereasons that apply to compliance withthe ROC numerical limitations.Examples of BMPs that representcurrent practices are, for example, use ofmud guns, proper mixing procedure,elimination of settling places foraccumulated solids. Examples of BMPsassociated with the use of the newsolids control technology are, for

example, operating cuttings dryers inaccordance with the manufacturer’sspecifications and maintaining a certainmass flux. If operators elect to use thisBMP option, they will be required todemonstrate compliance throughlimited retort monitoring of cuttings andadditional BMP paperwork. Paperworkrequirements are detailed in Appendix7 of subpart A of 40 CFR part 435.Paperwork cost and burden estimatesare detailed in Section IX.D of thepreamble.

d. Sediment Toxicity of SBFDischarged with Cuttings. As originallyproposed in February 1999 (64 FR 5491)and re-stated in April 2000 (65 FR21557), EPA is today promulgating aBAT limitation to control the maximumsediment toxicity of the SBF dischargedwith cuttings. This BAT limitationcontrols the sediment toxicity of theSBF discharged with cuttings as a non-conventional pollutant parameter and asan indicator for other pollutants in theSBF discharged with cuttings. Some ofthe toxic, priority, and non-conventional pollutants in the SBFdischarged with cuttings may include:(1) The base fluids such as enhancedmineral oils, internal olefins, linearalpha olefins, poly alpha olefins,paraffinic oils, C12–C14 vegetable estersof 2-hexanol and palm kernel oil, ‘‘lowviscosity’’ C8 esters, and otheroleaginous materials; (2) barite which isknown to generally have tracecontaminants of several toxic heavymetals such as mercury, cadmium,arsenic, chromium, copper, lead, nickel,and zinc; (3) formation oil whichcontains toxic and priority pollutantssuch as benzene, toluene, ethylbenzene,naphthalene, phenanthrene, andphenol; and (4) additives such asemulsifiers, oil wetting agents, filtrationcontrol agents, and viscosifiers.

The sediment toxicity of the SBFdischarged with cuttings is measured bythe modified sediment toxicity test (i.e.,ASTM E1367–92: ‘‘Standard Guide forConducting 10-day Static SedimentToxicity Tests With Marine andEstuarine Amphipods’’ (incorporated byreference and available from ASTM, 100Bar Harbor Drive, West Conshohocken,PA 19428), supplemented with thepreparation procedure specified inAppendix 3 of subpart A of 40 CFR part435) using a natural sediment orformulated sediment, 96-hour testingperiod, and Leptocheirus plumulosus asthe test organism. EPA is todaypromulgating a sediment toxicitylimitation for the SBF discharged withcuttings at the point of discharge thatwould only allow the discharge of SBF-cuttings using SBFs as toxic or lesstoxic, but not more toxic, than C16–C18



IOs SBFs. Alternatively, this limitationcould be expressed in terms of a ‘‘SBFsediment toxicity ratio’’ which isdefined as 96-hour LC50 of C16–C18

internal olefins SBF divided by the 96-hour LC50 of the SBF being dischargedwith cuttings at the point of discharge.EPA is promulgating a SBF sedimenttoxicity ratio of less than 1.0.

EPA finds that the sediment toxicitytest at the point of discharge is practicalas an indicator of the sediment toxicityof the drilling fluid at the point ofdischarge. As previously stated,establishing discharge limits on toxicityencourages the use of less toxic drillingfluids and additives. The modificationsto the sediment toxicity test includeshortening the test to 96-hours.Shortening the test will allow operators

to continue drilling operations while thesediment toxicity test is beingconducted on the discharged drillingfluid. Moreover, discriminatory poweris substantially reduced for the 10-daytest on drilling fluid as compared to the96-hour test (i.e., the 10-day test is oflower practical use in determiningwhether a SBF is substantially differentfrom OBFs). Finally, operatorsdischarging WBFs are alreadycomplying with a biological test at thepoint of discharge, the 96-hour SPPtoxicity test, which tests whole WBFaquatic toxicity using the test organismMysidopsis bahia.

The promulgated sediment toxicitylimitation would be achievable throughproduct substitution. EPA anticipatesthat the base fluids meeting the

sediment toxicity limitation wouldinclude vegetable esters, low viscosityesters, and internal olefins. Thereference C16–C18 IOs SBF will beformulated to meet the specifications inTable 1 and also contained in Appendix8 of subpart A of 40 CFR part 435. Thesediment toxicity discharge limitation istechnically and economicallyachievable because it is based oncurrently available base fluids that canbe used and are used across the widevariety of drilling situations found inU.S. offshore waters. EPA estimatesminimal monitoring costs associatedwith this limitation. Additionally, thesediment toxicity discharge limitationwill not lead to an increase of NWQIs.

TABLE 1.—PROPERTIES FOR REFERENCE C16–C18 IOS SBF USED IN DISCHARGE SEDIMENT TOXICITY TESTING

Mud weight of SBF discharged with cuttings (pounds per gallon) Reference C16–C18 IOsSBF (pounds per gallon)

Reference C16–C18 ISOsSBF synthetic to water

ratio (%)

8.5–11 ...................................................................................................................................... 9.0 75/2511–14 ....................................................................................................................................... 11.5 80/20> 14 .......................................................................................................................................... 14.5 85/15

Plastic Viscosity (PV), centipoise (cP) .................................................................................... ........................................ 12–30Yield Point (YP), pounds/100 sq. ft. ........................................................................................ ........................................ 10–2010-second gel, pounds/100 sq. ft. ........................................................................................... ........................................ 8–1510-minute gel, pounds/100 sq. ft. ............................................................................................ ........................................ 12–30Electrical stability, V ................................................................................................................. ........................................ > 300

G. NSPS Technology OptionsConsidered and Selected for DrillingFluid Associated with Drill Cuttings

The general approach followed byEPA for developing NSPS options wasto evaluate the best demonstrated SBFsand processes for control of prioritytoxic, non-conventional, andconventional pollutants. Specifically,EPA evaluated the technologies used asthe basis for BPT, BCT and BAT. TheAgency considered these options as astarting point when developing NSPSoptions because the technologies usedto control pollutants at existing facilitiesare fully applicable to new facilities.

EPA has not identified any morestringent treatment technology optionwhich it considered to represent NSPSlevel of control applicable to the SBF-cuttings wastestream. Further, EPA hasmade a finding of no barrier to entrybased upon the establishment of thislevel of control for new sources.Therefore, EPA is promulgating thatNSPS be established equivalent to BPTand BAT for conventional, priority, andnon-conventional pollutants. EPAconcluded that NSPS aretechnologically and economicallyachievable for the same reasons that

BAT is available and BPT is practical.EPA also concluded that NWQIs arereduced under the selected NSPS fornew wells due to the increasedefficiency of SBF drilling.

EPA concluded that a zero dischargerequirement for SBF-cuttings from newsources and the subsequent increaseduse of OBFs and WBFs would result in:(1) unacceptable NWQIs; and (2) morepollutant loadings to the ocean due tooperators switching from SBFs to lessefficient WBFs (see Sections II.B andV.F).

For the same reasons that the BATlimitations promulgated in today’s ruleare technologically and economicallyachievable, the promulgated NSPS arealso technologically and economicallyachievable. EPA’s analyses show thatunder the SBF zero discharge option forall areas as compared to current practiceas a basis for new source standards therewould be an increase of 3.4 millionpounds of cuttings annually shipped toshore for disposal in NOW sites and anincrease of 10.2 million pounds ofcuttings annually injected. This zerodischarge option would lead to anincrease in annual fuel use of 18,067BOE and an increase in annual airemissions of 528 tons. Finally, the SBF

zero discharge option for the GOMwould lead to an increase of 7.5 millionpounds of WBF-cuttings beingdischarged to U.S. Offshore waters. Thispollutant loading increase is a result ofoperators in U.S. Offshore waters (in theGOM) switching from efficient SBFdrilling to less efficient WBF drilling.EPA found these levels of NWQIsunacceptable and rejected the NSPSzero discharge option for SBF-cuttingsfrom new sources, except in CoastalCook Inlet, Alaska.

H. PSES and PSNS Technology Options

EPA is not establishing pretreatmentstandards for the facilities covered bythis rule. Based on information in therecord, EPA has not identified anyexisting offshore or Cook Inlet coastaloil and gas extraction facilities thatdischarge SBF and SBF-cuttings topublicly owned treatment works(POTWs), nor are any new facilitiesprojected to direct these wastes in suchmanner.



I. Best Management Practices (BMPs) toDemonstrate Compliance with NumericBAT Limitations and NSPS for DrillingFluid Associated with Drill Cuttings

Sections 304(e), 308(a), 402(a), and501(a) of the CWA authorize theAdministrator to prescribe BMPs as partof effluent limitations guidelines andstandards or as part of a permit (seeSection II.A.7). The BMP alternatives tonumeric limitations and standards inthis final rule are directed, among otherthings, at preventing or otherwisecontrolling leaks, spills, and dischargesof toxic and hazardous pollutants inSBF cuttings wastes (see 65 FR 21569for a list of the toxic and hazardouspollutants controlled by these BMPs).

As discussed in the April 2000 NODA(65 FR 21568), EPA considered threeoptions for the final rule for the BATlimitation and NSPS controlling SBFretained on discharged cuttings: (1) Asingle numeric discharge limitationwith an accompanying compliance testmethod; (2) allowing operators tochoose either a single numeric dischargelimitation with an accompanyingcompliance test method, or as analternative, a set of BMPs that employslimited cuttings monitoring; or (3)allowing operators to choose either asingle numeric discharge limitationwith an accompanying compliance testmethod or an alternative set of BMPsthat employ no cuttings monitoring.Under the third BMP option for SBF-cuttings (i.e., cuttings discharged andnot monitored), EPA also consideredwhether to require as part of the BMPoption, the use of a cuttings dryer asrepresentative of BAT/NSPS or to makethe use of a cuttings dryer optional.

EPA selects the second BMP option(i.e., allowing operators to choose eithera single numeric discharge limitationwith an accompanying compliance testmethod, or as an alternative, a set ofBMPs that employs limited cuttingsmonitoring) in the final rule. EPAselects this option as it provides for areasonable level of flexibility and isbased on quantifiable performancemeasures. EPA analyses show thatcuttings monitoring for the first third ofthe SBF footage drilled for a SBF wellinterval is a reliable indicator of theremaining two-thirds of the SBF-interval(see SBF Statistical Support Document;Docket No. W–98–26, Record No.III.B.a.18; Record No. III.B.b.15).Procedures for demonstratingcompliance with the selected BMPoption are given in Appendix 7 tosubpart A of part 435.

For the final rule, EPA did not haveenough data from across a wide varietyof drilling conditions (e.g., formation,

water depth, rig size) to demonstratethat BMPs without cuttings monitoringare equivalent to a numeric ROClimitation or standard. EPA is alsoconcerned that a set of BMPs withoutcuttings monitoring is not as objective toenforce. This is because with a numericlimitation or with the selected BMPoption with reduced cuttingsmonitoring, operators will need to keeprecords demonstrating compliance withthe numeric limitation. By contrast,under a BMP option with no numericlimit, there is no objective performancemeasure. This presents a particularproblem offshore, where real-timeinspections are not as practical as onland based industries. Therefore, EPArejected the third BMP option andcuttings dryer sub-option for SBF-cuttings (i.e., allowing operators tochoose either a single numeric dischargelimitation with an accompanyingcompliance test method or analternative set of BMPs that employ nocuttings monitoring). EPA concludedthat BMP option one and BMP optiontwo demonstrate the same level ofcompliance with the well averaged ROClimitation and standard (see SBFStatistical Support Document).Therefore, EPA selected BMP optiontwo over BMP option one to provideoperators with greater flexibility todemonstrate compliance with the wellaveraged ROC limitation and standard.

The BMP option promulgated in thisfinal rule includes informationcollection requirements that areintended to control the discharges ofSBF in place of numeric effluentlimitations and standards. Theseinformation collection requirementsinclude, for example: (1) Trainingpersonnel; (2) analyzing spills thatoccur; (3) identifying equipment itemsthat might need to be maintained,upgraded, or repaired; (4) identifyingprocedures for waste minimization; (4)performing monitoring (including theoperation of monitoring systems) toestablish equivalence with a numericcuttings retention limitation and todetect leaks, spills, and intentionaldiversion; and (5) generally toperiodically evaluate the effectivenessof the BMP alternatives.

BMP option two also requiresoperators to develop and, whenappropriate, amend plans specifyinghow operators will implement BMPoption two, and to certify to thepermitting authority that they have doneso in accordance with good engineeringpractices and the requirements of thefinal regulation. The purpose of thoseprovisions is, respectively, to facilitatethe implementation of BMP option twoon a site-specific basis and to help the

regulating authorities to ensurecompliance without requiring thesubmission of actual BMP Plans.Finally, the recordkeeping provisionsare intended to facilitate training, tosignal the need for different or morevigorously implemented BMPalternatives, and to facilitate complianceassessment. Details on burden and costestimates associated with theseadditional paperwork requirements arediscussed in Section IX.D.

VI. Costs and Pollutant Reductions forFinal Regulation

A. Compliance CostsEPA has analyzed the compliance

costs and incremental compliance costsor savings beyond current industrypractices and requirements, as well aspollutant loadings and incrementalloadings or reductions, EPA hasperformed these analyses for the Gulf ofMexico, offshore California, and coastalCook Inlet, Alaska, for baseline (current)costs and three control option costs.(Compliance costs were not developedfor other offshore regions in Alaskawhere oil and gas production activityexists because discharges of drillcuttings is not expected to occur inthese areas.) The three technology-basedoptions considered are: (1) BAT/NSPSOption 1 (controlled discharge optionwith discharges from the cuttings dryerand fines removal unit); (2) BAT/NSPSOption 2 (controlled discharge optionwith discharges from the cuttings dryerbut not the fines removal unit); and (3)BAT/NSPS Option 3 (Zero DischargeOption). Compliance costs/savings andpollutant increases/reductions are basedon: (1) Projected annual drilling activityin the three geographic regions; (2)model well volumes and wastecharacteristics; and (3) technology andmonitoring costs.

The compliance cost analysis beginswith the development of definedpopulations of wells on a regional andwell-type basis, develops per-wellestimates from an analysis of line-itemcosts, and then aggregates costs intototal regional and well-type costs byapplying per well costs to appropriatepopulations of wells. EPA estimatesbaseline compliance costs for currentindustry waste management practicesand for compliance with each regulatoryoption. EPA then calculated incrementalcompliance costs, which reflect thedifference between compliance costs fora regulatory option and baselinecompliance costs and the netcompliance costs or savings whichincorporate the costs along with savingsrealized by recovering drilling fluidsand more efficient drilling. Tables 2 and



3, for existing and new sourcesrespectively, list the total annualbaseline costs, compliance costs,incremental compliance costs, cost

savings, and net incrementalcompliance costs, calculated for eachgeographic area and regulatory option.

1. Large Volume Discharges

BILLING CODE 6560–50–U



2. Small Volume Discharges

As previously stated, EPA learnedthat SBF is controlled with zerodischarge at the drill floor, in the formof vacuums and sumps to retrievespilled fluid and associated wash water.EPA also learned that approximately 75barrels of fine solids and barite, whichhave an approximate SBF content of25%, can accumulate in the dead spacesof the mud pit, sand trap, and otherequipment in the drilling fluidcirculation system. Current practice is to

either wash these solids out with waterfor overboard discharge, or to retain thewaste solids for disposal. Severalhundred barrels (approximately 200 to400 barrels) of water are used to washout the mud pits. Industryrepresentatives also indicated to EPAthat those oil and gas extractionoperations that discharge wash waterand accumulated solids first recover freeSBF.

No additional costs were consideredfor controlling the minor spills of SBF

(e.g., < 5 gallons spilled during eachdrill string connection or disconnection)at the drill floor as: (1) Zero dischargepractices for recovering SBF at the drillfloor during drilling are the currentpractice; and (2) current practice is alsoto recover free SBF from the wash waterused at the drill floor. Additionally,since current practice is to first recoverfree SBF from accumulated solids anddischarge the accumulated solids withwash water, no additional costs were



considered for controlling thesedischarges.

EPA did not select zero discharge formanagement of these accumulatedsolids and associated wash water. EPAis defining these wastes as beingassociated with SBF-cuttings andsubject to the same requirements asother SBF discharges associated withSBF-cuttings. In particular, the final rulerequires operators to first recover freeoil from any accumulated solids orassociated wash water prior todischarging the accumulated solids andassociated wash water. These practicesare related to the current BPTlimitations (i.e., no discharge of free oil)and current industry practice usingsolids control equipment in order tocomply with the no free oil (sheen test)and SPP toxicity requirements.Accordingly, the requirement to recoverfree oil from accumulated solids andassociated wash water prior to dischargeis technologically and economicallyachievable with no additional NWQIs.Retort monitoring will also beperformed on the accumulated solidsand the retort monitoring results will beincorporated into the overall well-average SBF retained on cuttings valueas described in Appendix 7 of SubpartA of 40 CFR 435.

B. Pollutant ReductionsThe methodology for estimating

pollutant loadings and incrementalpollutant loadings (reductions)effectively parallels that of thecompliance cost analysis. The pollutantloadings analysis uses data from EPAand industry sources that quantify thepollutant characteristics of drillingfluids and cuttings waste streams(typically in, or converted to, a perbarrel basis). Waste volumes for the fourmodel well types (DWD, DWE, SWD,SWE) are coupled with these per barrelpollutant quantities to obtain per wellestimates of pollutant loadings. Theseper well estimates are then coupledwith the same well count data as usedin the cost analysis to derive well typeand aggregate regional pollutantloadings for the baseline and all options.Similar to the cost analysis, incrementalloadings (or removals) are obtained bydifference between the estimatedloadings of each option less baselineloadings, at both the BAT and NSPSlevel of control. This methodology ispresented in more detail in the SBFDevelopment Document.

The loadings and non-water qualityimpacts of wastes subject to zerodischarge limitations by this rule areimportant factors in its development.Zero discharge wastes have two fates:

they are injected into sub-seabedformations onsite or they aretransported to shore for disposal vialand farming or injection. The allocationof zero discharge wastes between onsiteinjection versus onshore disposal followthe same well type and regionalassumptions as were used for the costanalysis. Zero discharge loadings(removals) are determined identically todischarge loadings; they are presentedin detail in the Development Documentand are summarized below.

Table 4 presents a summary ofindustry-wide results, by region, forBAT baseline loadings, both dischargeoptions, and the zero discharge option,as well as their incremental loadings(removals). Table 5 presents thisinformation for new sources.

The BCT cost test evaluates thereasonableness of BCT candidatetechnologies as measured from BPTlevel compliance costs and pollutantreductions. The proposed BCT level ofregulatory control is equivalent to theBPT level of control for both thedischarge options and the zerodischarge option. If there is noincremental difference between BPTand BCT, there is no cost to BCT andthus the option passes both BCT costtests.



TABLE 5.—SUMMARY ANNUAL SBF POLLUTANT LOADINGS, NEW SOURCES

[In pounds/year]

Technology basisSBF pollutant loadings(reductions)—Gulf of

Mexico

Baseline/Current Practice Technology Loadings:Discharge with LTA of 10.2% SBF ROC ................................................................................................................... 17,405,127Discharge of WBF and cuttings ................................................................................................................................. 92,903,606Discharge of OBF ....................................................................................................................................................... 0

Total Baseline Loadings ......................................................................................................................................... 110,308,733

Technology Option Loadings:BAT/NSPS Option 1.Discharge with LTA of 4.03% SBF ROC ................................................................................................................... 20,241,106Discharge of WBF and cuttings ................................................................................................................................. 87,462,923Discharge of OBF ....................................................................................................................................................... 0

Total NSPS 1 Loadings .......................................................................................................................................... 107,704,029

BAT/NSPS Option 2.Discharge with LTA of 3.82% SBF ROC ................................................................................................................... 19,722,488Discharge of WBF and cuttings ................................................................................................................................. 87,462,923Discharge of OBF ....................................................................................................................................................... 0


BAT/NSPS Option 3—Zero Discharge.Discharge of SBF ....................................................................................................................................................... 0Discharge of WBF and cuttings ................................................................................................................................. 100,387,607Discharge of OBF ....................................................................................................................................................... 0


Incremental Technology Option Loadings (Reductions):BAT/NSPS Option 1: Discharge with 4.03% retention of SBF on cuttings ............................................................... (2,604,704)BAT/NSPS Option 2: Discharge with 3.82% retention of SBF on cuttings ............................................................... (3,123,322)BAT/NSPS Option 3: Zero Discharge of SBF-wastes via land disposal or onsite injection ..................................... (9,921,126)

NOTE: EPA estimates the following GOM WBF/OBF/SBF new sources: Baseline—38/2/20; BAT/NSPS Option 1 & 2—35/1/24; and BAT/NSPSOption 3—42/15/3. EPA estimates no new sources for Offshore California or Cook Inlet, AK.

NOTE: The following terms are used in this table: long-term average (LTA) and retention on cuttings (ROC).

VII. Economic Impacts of FinalRegulation

EPA evaluated the economic effects ofthe options considered for today’sregulation. The methodology and resultsare presented in detail in the SBFEconomic Analysis (EPA–821–B–00–012). The following discussion presentsa summary of that analysis and itsconclusions. Small business impacts aresummarized below and in Section IX.B.Environmental justice issues aresummarized in Section IV.C.

A. Impacts Analysis

EPA examined the potential impactsof the rule several ways: effects ondrilling well costs, changes to financialperformance of drilling facilities andproduction, impacts on small firms, andsecondary impacts. The economicmethodology used to examine potentialimpacts on drilling well costs, firms,and secondary impacts is the same asthat used for the February 1999 proposal(see 64 FR 5521–5527; February 1999

proposal Economic Analysis (EPA–821–B–98–020)).

In response to comments and newdata, EPA developed a series ofeconomic models for existing and newdeep water projects in the Gulf ofMexico similar to those used for theOffshore and Coastal rules (see 58 FR12454–12512 and 61 FR 66086–66130).This additional analysis is discussed inthe April 2000 NODA (65 FR 21558).The models focus on the deep waterGulf because it is the region with thehighest level of current drilling withand future interest in drilling withSBFs. The economic models are basedon a cash flow approach. Revenues arebased on an assumed price of oil,current and projected production of oiland gas, well production decline rates,and royalty rates. Operating costs arebased on an assumed cost per BOEproduced. The models are based on datafrom MMS and industry (see Summaryof Data to be Used In EconomicModeling for more details on themethodology, data, and parameters on

which the models are based and howthe models were constructed (DocketNo. W–98–26, Section III.G of theRulemaking Record)) and SBF EconomicAnalysis, Appendix A. EPA received nocomments on this NODA with respect tothe economic methodology or the data.

The costs and revenues are comparedyearly and the project is assumed to runfor 30 years or to shut in when operatingcosts exceed revenues. That is, theeconomic models have differinglifetimes according to projectcharacteristics and each model mayhave a shortened lifetime as a result ofincremental costs. The model thencalculates the lifetime of the project,total production, and the net presentvalue of the operation (net income of theoperation over the life of the project interms of today’s dollars), whichincludes the net operating earnings,taxes, expenditures on drilling, othercapital expenditures, etc. A positive netpresent value means that the project isa good investment. In these cases, thereturn is greater than the discount rate,



which represents the opportunity cost ofcapital. If the net present value isnegative, it means that money wouldhave been better invested elsewhere. Forexisting projects, the model uses currentoperations; all expenditures in prioryears, such as exploration, delineation,and infrastructure development costsare considered sunk costs and are notaddressed. For new projects, the modeluses data and parameters about timingof the various phases of exploration,delineation and development, alongwith cost estimates about costs incurredduring these phases to compute a fulllifetime financial model of theseprojects.

Each model is run twice—with andwithout the change due to pollutioncontrol. The models support changes inboth directions—i.e., costs or savings. Ifa model shows the net present value ofa project to be positive in the baseline,but would have a negative net presentvalue under any of the regulatoryoptions, some or all of the wells wouldnot be drilled. This difference betweenbaseline and postcompliance wouldgenerate production impacts.

The likely outcome of today’s rule isan overall savings associated with theability to discharge SBF cuttings (seeSection VI.A). The cost model (whichprovides the input to the economicmodels) projects that the savings exceedany incremental costs of compliance inthe aggregate. EPA does not expect thealternate higher ROC limitation andstandard for drilling fluids with thestock base fluid performance of esters toaffect costs. EPA expects that operatorswill likely use ester-based SBFs for theincreased flexibility and not for anyeconomic benefits. The results of theeconomic models indicate no adverseimpacts on drilling well costs(exploratory or developmental), projectlifetime, or production for both BATand NSPS projects. There are no adverseimpacts on firms, employment, trade, orinflation.

B. Small Business AnalysisAlthough today’s rule will not have a

significant economic impact on asubstantial number of small entities (seeSection VII.A), EPA assessed theimpacts of the rule on small businesses.The small business analysis is describedmore fully in Chapter 6 of the SBFEconomic Analysis.

The small business definitions andthe methodology were outlined in theApril 2000 NODA and the February1999 Proposal Economic Analysis andhave not changed. Briefly, EPA relied onthe Small Business Administration’ssize standards to determine whether afirm is a small business. If EPA could

not find employment or revenue data toconfirm a firm’s size, it was classified as‘‘potentially’’ small. EPA identified 40small and potentially small firms. Asnoted in the previous paragraph, today’srule results in cost savings, and EPAprojects no adverse impacts on smallbusinesses.

VIII. Water Quality and Non-WaterQuality Environmental Impacts of FinalRegulation

A. Overview of Water Quality and Non-Water Quality Environmental Impacts

EPA conducted various analyses toassess the impact of the final regulationon water quality, sediment quality, andhuman health. In general, EPA hasfound that no adverse impacts areexpected from controlled discharges ofSBFs.

B. Water Quality Modeling

In order to assess the impacts ofpotential SBF discharges to thereceiving waters, EPA conducted porewater, water column, and sedimentguidelines analyses. EPA calculatedpollutant concentrations for both thewater column and pore water andcompared them to the respective EPArecommended marine water qualitycriteria or to applicable state standardsto determine the nature and magnitudeof any projected water qualityexceedances. Details of the analyses andresults are presented in the final SBFEnvironmental Assessment.

EPA included the discharge of WBFsin the engineering analyses (see SectionII.A). Environmental impacts such aswater column, pore water, fish tissueand human health risk analyses werenot estimated for the discharge of WBFsversus the use and discharge of SBFcuttings. However, industry hasprovided information that drilling issignificantly more efficient using SBFsrather than WBFs because hole volumeswith SBFs are approximately 1.8 timessmaller. Therefore, the pollutantloadings of appropriately controlledSBF discharge are less than pollutantloadings associated with controlledWBF discharge.

1. Water Column Water QualityAnalyses

There are no water quality criteriaexceedances in the water column forany of the regulatory options beingconsidered including the ROC optionbased on data from all four cuttingsdryer technologies for drilling fluidswith the sediment toxicity andbiodegradation characteristics of ester-based SBFs which results in a slightlyhigher LTA. Also, no Alaska state water

quality standards are exceeded underthe discharge options in Cook Inlet,Alaska.

2. Pore Water Quality AnalysesAs described above in Section III.D.1,

the addition of several seabed surveydata changed the estimated SBFsediment concentration at 100 meters(328 feet) as used in the pore waterquality analyses. The revised analysesestimate that baseline (or BPT) porewater pollutant concentrations at 100meters from the discharge exceedrecommended water quality criteria forthe heavy metal, chromium, for twomodel well types, shallow waterexploratory and deep water exploratory.There are no pore water exceedances ofany of the Alaska state water qualitystandards for potential Cook Inlet,Alaska discharges. Also, there are nopore water exceedances under thecontrolled SBF discharges (i.e., BAT/NSPS Options 1 and 2) including theROC option based on data from all fourcuttings dryer technologies for drillingfluids with the sediment toxicity andbiodegradation characteristics of ester-based SBFs which results in a slightlyhigher LTA.

3. Sediment Guidelines AnalysesThe EPA proposed sediment

guidelines for the protection of benthicorganisms assesses potential benthicimpacts of certain metals. The revisedanalyses, based on revised pore waterconcentrations, result in 2 exceedancesonly under the baseline (or BPT)conditions. There are no sedimentguidelines exceedances undercontrolled SBF discharge conditions(i.e., BAT/NSPS Options 1 and 2)including the ROC option based on datafrom all four cuttings dryer technologiesfor drilling fluids with the sedimenttoxicity and biodegradationcharacteristics of ester-based SBFswhich results in a slightly higher LTA.

C. Human Health Effects ModelingThe human health risk analyses were

revised to incorporate changes to thefish consumption rates (see SectionIII.D.b). The revised analyses show norisk to human health.

D. Seabed SurveysEPA reviewed the seabed surveys

submitted during public comment to theApril 2000 NODA. As previously stated,EPA used data from two surveys drillingsix wells with SBFs in theenvironmental assessment analyses.Additionally, EPA also receivedinformation on the on-going jointIndustry/MMS GOM seabed survey. TheIndustry/MMS workgroup has



completed the first two cruises of thefour cruise study (see Section III.D.1).Outside of a 50–100′ radius from thedrilling facility, no visible cuttingsaccumulations (large or small) weredetected at any of the drilling facilitysurvey sites.

E. Energy Impacts

As described in Sections III.E andIV.E, EPA included additional data andrevised several parameters in estimating

energy impacts of the final SBF rule.EPA estimated the amount of fuelrequired, expressed as barrels of oilequivalents per year (BOE/yr), tooperate the equipment associated witheach of the regulatory options as well asthe fuel consumed by daily rigoperations. EPA also estimated thecurrent energy requirements of WBFdischarge in order to determine therelative decrease in impacts of SBFversus WBF use. EPA does not expect

the alternate higher ROC limitation andstandard for drilling fluids with thestock base fluid performance of esters toaffect energy impacts becauseequipment used under the ester option(e.g., shale shakers, cuttings dryer, finesremoval unit) has the same or similarenergy requirements. The results of theenergy impact analysis are presented inTables 6 and 7 for existing and newsources, respectively.

TABLE 6.—INCREMENTAL SUMMARY ANNUAL ENERGY IMPACTS, EXISTING SOURCES

Technology basis

Energy impacts: Reductions (Increases)a fuel use (BOE/yr)

Gulf of Mex-ico

OffshoreCalifornia

Cook Inlet,AK Total

BAT/NSPS Option 1: Discharge with LTA of 4.03% SBF ROC .............................. 202,146 0 19 202,165BAT/NSPS Option 2: Discharge with LTA of 3.82% SBF ROC .............................. 195,124 0 0 195,124BAT/NSPS Option 3: Zero Discharge of SBF-wastes via land disposal or onsite

injection ................................................................................................................ (346,459) (6,138) (6,067) (358,664)

a Annual fuel usage reductions or increases are incremental to baseline/current practice (i.e., discharge of SBF-cuttings at 10.2% ROC in theGOM and zero discharge in Offshore California and Cook Inlet, AK).

Note: BOE = Barrels of Oil Equivalent.Note: The following terms are used in this table: long-term average (LTA) and retention on cuttings (ROC).

TABLE 7.—INCREMENTAL SUMMARY ANNUAL ENERGY IMPACTS, NEW SOURCES

Technology basisEnergy impacts: Reduc-

tions (increases)a fuel use(BOE/yr)

BAT/NSPS Option 1: Discharge with LTA of 4.03% SBF ROC ....................................................................................... 6330BAT/NSPS Option 2: Discharge with LTA of 3.82% SBF ROC ....................................................................................... 5693BAT/NSPS Option 3: Zero Discharge of SBF-wastes via land disposal or onsite injection ............................................. (18,067)

a Annual fuel usage reductions or increases are incremental to baseline/current practice (i.e., discharge of SBF-currings at 10.2% ROC in theGOM).

Note: BOE = Barrels of Oil Equivalent.Note: The following terms are used in this table: long-term average (LTA) and retention on cuttings (ROC).Note: EPA estimates no new sources for Offshore California or Cook Inlet, AK.

F. Air Emission Impacts

EPA calculated the air emissions,expressed as short tons per year,resulting from activities associated witheach of the regulatory options. Airemissions are a function of the: (1) Typeof fuel burned (e.g., natural gas ordiesel); and (2) amount of fuelconsumed as determined from thelength of equipment operation and the

fuel consumption rate. Themethodology and modeling parametersparallel that of the energy impactanalysis as the amount of fuel consumedis the basis for the air emissionsanalysis. Therefore, the air emissionsanalysis includes the estimate ofemissions of daily rig operations and anestimate of WBF drilling operation airemissions. EPA does not expect thealternate higher ROC limitation and

standard for drilling fluids with thestock base fluid performance of esters toaffect air emissions because equipmentused under the ester option (e.g., shaleshakers, cuttings dryer, fines removalunit) has the same or similar airemissions. The results of the airemission analysis are presented inTables 8 and 9 for existing and newsources, respectively.

TABLE 8.—INCREMENTAL SUMMARY ANNUAL AIR EMISSIONS, EXISTING SOURCES

Technology basis

Annual Air Emission Reductions (Increases) a (tons/yr)

Gulf ofMexico

OffshoreCalifornia

Cook Inlet,AK Total

BAT/NSPS Option 1: Discharge with LTA of 4.03% SBF ROC .............................. 3,172 0 0 3,172BAT/NSPS Option 2: Discharge with LTA of 3.82% SBF ROC .............................. 3,074 0 (1) 3,073BAT/NSPS Option 3: Zero Discharge of SBF-wastes via land disposal or onsite

injection ................................................................................................................ (5,414) (94) (94) (5,602)

a Annual air emissions reductions or increases are incremental to baseline/current practice (i.e., discharge of SBF-cuttings at 10.2% ROC in theGOM and zero discharge in Offshore California and Cook Inlet, AK).

Note: 1 ton = 2000 lbs.Note: The following terms are used in this table: long-term average (LTA) and retention cuttings (ROC).



TABLE 9.—INCREMENTAL SUMMARY AIR EMISSIONS, NEW SOURCES—GULF OF MEXICO

Technology basis

Annual airemissionsreduction

(increases) a

(tons/yr)

BAT/NSPS Option 1: Discharge with LTA of 4.03% SBF ROC ............................................................................................................. (136)BAT/NSPS Option 2: Discharge with LTA of 3.82% SBF ROC ............................................................................................................. (145)BAT/NSPS Option 3: Zero Discharge of SBF-wastes via land disposal or onsite injection ................................................................... (528)

a Annual air emissions reductions or increases are incremental to baseline/current practice (i.e., discharge of SBF-cuttings at 10.2% ROC in theGOM).

Note: 1 ton = 2000 lbs.Note: The following terms are used in this table: long-term average (LTA) and retention on cuttings (ROC).Note: EPA estimates no new sources for Offshore California or Cook Inlet, AK.

G. Air Emissions Monetized HumanHealth Benefits

EPA estimated emissions associatedwith each of the regulatory options aspart of the NWQI analyses. Thepollutants considered in the NWQIanalyses are nitrogen oxides ( NOX),volatile organic carbon (VOC),particulate matter (PM), sulfur dioxide(SO2), and carbon monoxide (CO). Ofthese pollutants, EPA monetized thehuman health benefits or impactsassociated with VOC, PM, and SO2

emissions using the methodologypresented in the EnvironmentalAssessment of the Final EffluentLimitations Guidelines and Standardsfor the Pharmaceutical Manufacturing

Industry (EPA–821–B–98–008). Each ofthese pollutants have human healthimpacts and reducing these emissionscan reduce these impacts.

Several VOCs exhibit carcinogenicand systemic effects and VOCs, ingeneral, are precursors to ground-levelozone, which negatively affects humanhealth and the environment. PMimpacts include aggravation ofrespiratory and cardiovascular diseaseand altered respiratory tract defensemechanisms. SO2 impacts include nasalirritation and breathing difficulties inhumans and acid deposition in aquaticand terrestrial ecosystems.

The unit values (in 1990 dollars) are$489 to $2,212 per megagram (Mg) ofVOC; $10,823 per Mg of PM; and $3,516

to $4,194 per Mg of SO2. Using theEngineering News Record ConstructionCost Index (see www.enr.com/cost/costcci.asp) these conversion factors arescaled up using the ratio of 6060:4732(1999$:1990$). EPA does not expect thealternate higher ROC limitation andstandard for drilling fluids with thestock base fluid performance of esters toaffect monetized benefits becauseequipment used under the ester option(e.g., shale shakers, cuttings dryer, finesremoval unit) has the same or similar airemissions. Following is a summary ofthe monetized benefits for each of theregulatory options for both existing andnew sources.

BILLING CODE 6560–50–U



H. Solid Waste Impacts

EPA calculated the amount of wastecuttings that would be land disposed,injected onshore, and/or injected onsitein each regulatory scenario, anddetermined that there would be aconsiderable reduction in the amount ofdrill cuttings land disposed and injectedwith the implementation of a controlleddischarge option for SBF-cuttings.

EPA’s analyses show that under theSBF-cuttings zero discharge option ascompared to current practice, for U.S.Offshore waters existing sources, therewould be an annual increase of 35million pounds of cuttings shipped toshore for disposal in non-hazardousoilfield waste (NOW) sites and anincrease of 166 million pounds ofcuttings injected. In addition, under the

SBF-cuttings zero discharge option,operators would use the more toxicOBFs. The zero discharge option forSBF-cuttings would lead to an increasein annual fuel usage of 358,664 BOE andan increase in annual air emissions of5,602 tons. Finally, the SBF-cuttingszero discharge option in the U.S.Offshore waters would lead to anincrease of 51 million pounds of WBFcuttings being discharged to U.S.Offshore waters. This pollutant loadingincrease is a result of GOM operatorsswitching from efficient SBF drilling toless efficient WBF drilling.

Additionally, EPA’s analyses showthat under the SBF-cuttings zerodischarge option as compared to currentpractice, for GOM new sources, therewould be an annual increase of 3.4

million pounds of drill cuttings shippedto shore for disposal in NOW sites andan increase of 10.2 million pounds ofdrill cuttings injected. These zerodischarge options for SBF-cuttingswould lead to an increase in annual fueluse of 18,067 BOE and an increase inannual air emissions of 528 tons.Finally, the SBF-cuttings zero dischargeoption in the GOM would lead to anincrease of 7.5 million pounds of WBF-cuttings being discharged to U.S.Offshore waters. Again, this pollutantloading increase is a result of GOMoperators switching from efficient SBFdrilling to less efficient WBF drilling.

I. Other Factors

EPA also considered the impact of theeffluent limitations guidelines and



standards on safety. EPA has identifiedtwo safety issues related to drillingfluids: (1) Deleterious vapors generatedby organic materials in drilling fluids;and (2) waste hauling activities thatincrease the risk of injury to workers.

1. Vapors Generated by OrganicMaterials in Drilling Fluids

One of the key concerns inexploration and production projects isthe exposure of wellsite personnel tovapors generated by organic materials indrilling fluids (Docket No. W–98–26,Record No. III.D.12). Areas on thedrilling location with the highestexposure potentials are sites near solidscontrol and open pits. These areas areoften enclosed in rooms and ventilatedto prevent unhealthy levels of vaporsfrom accumulating. If the total volumeof organic vapors can be reduced thenany potential health effects will also bereduced regardless of the nature of thevapors.

Generally speaking the aromaticfraction of the vapors is the most toxicto the mammalian system. The highvolatility and absorbability through thelungs combined with their high lipidsolubility serve to increase theirtoxicity. OBFs have a high aromaticcontent and vapors generated fromusing these drilling fluids includearomatics (e.g., alkybenzenes,naphthalenes, and alkyl-naphthalenes),alkanes (e.g., C 7 –C 18 straight chainedand branched), and alkenes. Someminerals oils also generate vapors thatcontain the same types of chemicalcompounds, but generally at lowerconcentrations, as those found in thediesel vapors (e.g., aromatics, alkanes,cyclic alkanes, and alkenes). BecauseSBF are manufactured from compoundswith specifically defined compositions,the subsequent compound can excludetoxic aromatics. Consequently, toxicaromatics can be excluded from thevapors generated by using SBFs.

In general, SBFs (e.g., esters, LAOs,PAOs, IOs) generate much lowerconcentrations of vapors than do OBFs(Docket No. W–98–26, Record No.III.D.12). Moreover, the vaporsgenerated by these SBFs are less toxicthan traditional OBFs because they donot contain aromatics.

2. Waste Hauling ActivitiesIndustry has commented in previous

effluent guidelines, such as the CoastalSubcategory Oil and Gas Extraction andDevelopment ELG, that a zero dischargerequirement would increase the risk ofinjury to workers due to increased wastehauling activities. These activitiesinclude vessel trips to and from thedrilling facility to haul waste, transfer of

waste from the drilling facility onto aservice vessel, and transfer in port ontoa barge or dock.

EPA has identified and reviewedadditional data sources to determine thelikelihood that imposition of a zerodischarge limitation on cuttingscontaminated with SBF could increaserisk of injury due to additional wastehauling demands. The sources of safetydata are the U.S. Coast Guard (USCG),the Minerals Management Service(MMS), the American PetroleumInstitute (API), and the Offshore MarineService Association (OMSA). Thefollowing is a summary of the findingsfrom this review.

The data indicate that there arereported incidents that are associatedwith the collection, hauling, andonshore disposal of wastes fromoffshore. However, the data do notdistinguish whether any of theseincidents can be attributed to specificwaste management activities.

Most offshore incidents are due tohuman error or equipment failure. Therate at which these incidents occur willnot be changed significantly byincreased waste management activities.However, if the number of man hoursand/or equipment hours are increased,there will be more reportable incidentsgiven an unchanged incident rate. Thesepotential increases may be offset byreduced incident rates throughincreased training or equipmentmaintenance and inspection; but thesechanges cannot be predicted. Oneindication that training andmaintenance can reduce incident ratesis a 1998 API report entitled ‘‘1997Summary of U.S. Occupational Injuries,Illnesses, and Fatalities in the PetroleumIndustry,’’ which established that injuryincident rates have been decreasing overthe last 14 years. If this decreasecontinues, there should be no increasein the number of safety incidents due toa requirement to haul SBF-contaminatedcuttings to shore for disposal. Thedetails of this analysis are available ina technical support document in therule record for today’s final rule.

IX. Regulatory Requirements

A. Executive Order 12866: RegulatoryPlanning and Review

Under Executive Order 12866 (58 FR51735 (October 4, 1993)), the Agencymust determine whether the regulatoryaction is ‘‘significant’’ and thereforesubject to OMB review and therequirements of the Executive Order.The Order defines ‘‘significantregulatory action’’ as one that is likelyto result in a rule that may:

(1) Have an annual effect on theeconomy of $100 million or more oradversely affect in a material way theeconomy, a sector of the economy,productivity, competition, jobs, theenvironment, public health or safety, orState, local, or tribal governments orcommunities;

(2) Create a serious inconsistency orotherwise interfere with an action takenor planned by another agency;

(3) Materially alter the budgetaryimpact of entitlements, grants, user fees,or loan programs or the rights andobligations of recipients thereof; or

(4) Raise novel legal or policy issuesarising out of legal mandates, thePresident’s priorities, or the principlesset forth in the Executive Order.

Pursuant to the terms of ExecutiveOrder 12866, it has been determinedthat this rule is a ‘‘significant regulatoryaction.’’ As such, this action wassubmitted to OMB for review. Changesmade in response to OMB suggestions orrecommendations are documented inthe public record.

B. Regulatory Flexibility Act (RFA), asamended by the Small BusinessRegulatory Enforcement Fairness Act of1996 (SBREFA), 5 USC 601 et. seq.

The RFA generally requires an agencyto prepare a regulatory flexibilityanalysis of any rule subject to noticeand comment rule requirements underthe Administrative Procedure Act or anyother statute unless the agency certifiesthat the rule will not have a significanteconomic impact on a substantialnumber of small entities. Small entitiesinclude small businesses, smallorganizations, and small governmentaljurisdictions.

For purposes of assessing the impactsof today’s rule on small entities, smallentity is defined as: (1) A small businesswith fewer than 500 employees for oiland gas production operators and lessthan $5 million per year in revenues foroil and gas services providers (i.e., thedefinitions from SBA’s size standards);(2) a small governmental jurisdictionthat is a government of a city, county,town, school district, or special districtwith a population of less than 50,000;and (3) a small organization that is anynot-for-profit enterprise which isindependently owned and operated andis not dominant in its field. Afterconsidering the economic impact oftoday’s final rule on small entities, Icertify that this action will not have asignificant economic impact on asubstantial number of small entities.Today’s rule affects small businessesonly; there are no impacts on smallgovernmental jurisdictions or smallorganizations.



In determining whether a rule has asignificant economic impact on asubstantial number of small entities, theimpact of concern is any significantadverse economic impact on smallentities. Since the primary purpose ofthe regulatory flexibility analysis is toidentify and address regulatoryalternatives ‘‘which minimizes anysignificant economic impact of theproposed rule on small entities.’’ 5U.S.C. Sections 603 and 604. Thus, anagency may certify that a rule will nothave a significant economic impact ona substantial number of small entities ifthe rule relieves regulatory burden, orotherwise has a positive economic effecton all of the small entities subject to therule.

EPA projects that today’s rule willresult in operational savings and willhave no adverse economic impacts.These conclusions apply to all firms,both large and small. EPA estimates thatbetween five and 40 small businesses(between five and 40% of all firms) arecovered by today’s rule. If the smallbusinesses are using SBF and continueto do so, or if they switch to SBF, theyneed to comply with today’s effluentlimitations. EPA estimates that theoperational savings associated with anallowable SBF-cuttings discharge willresult in an economic advantage,contrasted to other SBF-cuttingsregulatory scenarios. EPA selected thecontrolled discharge option which willallow operators to use of SBF in placeof OBF and WBFs. Using SBFs in placeof OBFs will generally shorten thelength of the drilling project andeliminate the need to barge to shore orre-inject OBF-waste cuttings, therebyreducing costs and NWQI such as fueluse, air emissions, and land disposal ofOBFs. Use of SBFs in place of WBFswould also lead to: (1) a decrease incosts and NWQIs due to the decreasedlength of the drilling project; and (2) aper well decrease of pollutantsdischarged due to improved technicalperformance of SBFs. EPA estimatesthat the rule will result in annualsavings of $48.9 million and no adverseeconomic impacts to the industry as awhole. Further, after considerable study,EPA’s record indicates that there will beno significant economic impacts to anysmall entity subject to the rule. The SBFEconomic Analysis describes theseresults in more detail. We have thereforeconducted that today’s final rule willrelieve regulatory burden for all smallentities.

C. Submission to Congress and theGeneral Accounting Office

The Congressional Review Act, 5U.S.C. 801 et seq., as added by the Small

Business Regulatory EnforcementFairness Act of 1996, generally providesthat before a rule may take effect, theagency promulgating the rule mustsubmit a rule report, which includes acopy of the rule, to each House of theCongress and to the Comptroller Generalof the United States. EPA will submit areport containing this rule and otherrequired information to the U.S. Senate,the U.S. House of Representatives, andthe Comptroller General of the UnitedStates prior to publication of the rule inthe Federal Register. A major rulecannot take effect until 60 days after itis published in the Federal Register.This action is not a ‘‘major rule’’ asdefined by 5 U.S.C. 804(2). This rulewill be effective February 21, 2001.

D. Paperwork Reduction ActThe Office of Management and Budget

(OMB) has approved the informationcollection requirements contained inthis rule under the provisions of thePaperwork Reduction Act, 44 U.S.C.3501 et seq. and has assigned OMBcontrol number 2040–0230.

The information collectionrequirements are related to the optionaluse of Best Management Practices(BMPs) in order to reduce SBF-cuttingsmonitoring. Operators that elect to notuse the BMP alternative are not subjectto the information collectionrequirements in today’s final rule. BMPsare inherently pollution preventionpractices. BMPs may include theuniverse of pollution preventionencompassing productionmodifications, operational changes,material substitution, materials andwater conservation, and other suchmeasures. BMPs include methods toprevent toxic and hazardous pollutantsfrom reaching receiving waters. BecauseBMPs are most effective when organizedinto a comprehensive facility BMP Plan,EPA is requiring operators to completea BMP Plan when they select the BMPalternative.

The BMP alternative requiresoperators to develop and, whenappropriate, amend plans specifyinghow operators will implement thespecified BMP alternative, and to certifyto the permitting authority that theyhave done so in accordance with goodengineering practices and therequirements of the regulation. Thepurpose of those provisions is,respectively, to facilitate theimplementation of BMP alternative on asite-specific basis and to help theregulating authorities to ensurecompliance without requiring thesubmission of actual BMP Plans.Finally, the recordkeeping provisionsare intended to facilitate training, to

signal the need for different or morevigorously implemented BMPs, and tofacilitate compliance assessment.

The information collectionrequirements in the final rule include,for example: (1) Training personnel; (2)analyzing spills that occur; (3)identifying equipment items that mightneed to be maintained, upgraded, orrepaired; (4) identifying procedures forwaste minimization; (5) performingmonitoring (including the operation ofmonitoring systems) to establishequivalence with a numeric cuttingsretention limitation and to detect leaks,spills, and intentional diversion; and (6)generally to periodically evaluate theeffectiveness of the BMP alternatives.

EPA does not expect that anyconfidential business information ortrade secrets will be required from oiland gas extraction operators as part ofthis ICR. If information submitted inconjunction with this ICR were tocontain confidential businessinformation, the respondent has theauthority to request that the informationbe treated as confidential businessinformation. All data so designated willbe handled by EPA pursuant to 40 CFRpart 2. This information will bemaintained according to proceduresoutlined in EPA’s Security Manual PartIII, Chapter 9, dated August 9, 1976.Pursuant to section 308(b) of the CWA,effluent data may not be treated asconfidential.

EPA estimated the burden and coststo the regulated community(approximately 67 SBF well drillingfacilities annually) and EPA, the NPDESpermit control authority, for datacollection and record keeping associatedwith implementation of the BMPalternative. EPA estimates the publicreporting burden for the selected BMPoption as 787 hours per respondent peryear (i.e., (16,750 initial hours/3 years +47,168 annual hours/year)/67 SBF welloperators). EPA also estimated theannual burden for EPA Regions, theNPDES permit controlling authorities, toreview BMPs and ensure compliance.EPA estimates that essentially all of theSBF discharges will occur in Federaloffshore waters or in Cook Inlet, Alaska,where EPA Region X retains NPDESpermit controlling authority. The EPARegional burden for reviewing BMPPlans is estimated at 380 hours per year(i.e., (536 initial hours/3 years + 201annual hours/year)).

EPA estimates the public reportingcosts as $24,058 per respondent per year(i.e., ($1,235,313 initial costs/3 years +$1,200,138 annual costs/year)/67 SBFwell operators). The EPA Regional costsfor reviewing BMP Plans is estimated atapproximately $12,149 per year (i.e.,



($17,152 initial costs/3 years + $6,432annual costs/year)).

Burden means the total time, effort, orfinancial resources expended by personsto generate, maintain, retain, or discloseor provide information to or for aFederal agency. This includes the timeneeded to review instructions; develop,acquire, install, and utilize technologyand systems for the purposes ofcollecting, validating, and verifyinginformation, processing andmaintaining information, and disclosingand providing information; adjust theexisting ways to comply with anypreviously applicable instructions andrequirements; train personnel to be ableto respond to a collection ofinformation; search data sources;complete and review the collection ofinformation; and transmit or otherwisedisclose the information.

An Agency may not conduct orsponsor, and a person is not required torespond to a collection of informationunless it displays a currently valid OMBcontrol number. The OMB controlnumbers for EPA’s regulations are listedin 40 CFR part 9 and 48 CFR chapter 15.EPA is amending the table in 40 CFRpart 9 of currently approved ICR controlnumbers issued by OMB for variousregulations to list the informationrequirements contained in this finalrule.

E. Unfunded Mandates Reform ActTitle II of the Unfunded Mandates

Reform Act of 1995 (UMRA), PublicLaw 104–4, establishes requirements forFederal agencies to assess the effects oftheir regulatory actions on State, local,and tribal governments and the privatesector. Under section 202 of the UMRA,EPA generally must prepare a writtenstatement, including a cost-benefitanalysis, for proposed and final ruleswith ‘‘Federal mandates’’ that mayresult in expenditures to State, local,and tribal governments, in the aggregate,or to the private sector, of $100 millionor more in any one year. Beforepromulgating an EPA rule for which awritten statement is needed, section 205of the UMRA generally requires EPA toidentify and consider a reasonablenumber of regulatory alternatives andadopt the least costly, most cost-effective or least burdensome alternativethat achieves the objectives of the rule.The provisions of section 205 do notapply when they are inconsistent withapplicable law. Moreover, section 205allows EPA to adopt an alternative otherthan the least costly, most cost-effectiveor least burdensome alternative if theAdministrator publishes with the finalrule an explanation why that alternativewas not adopted. Before EPA establishes

any regulatory requirements that maysignificantly or uniquely affect smallgovernments, including tribalgovernments, it must have developedunder section 203 of the UMRA a smallgovernment agency plan. The plan mustprovide for notifying potentiallyaffected small governments, enablingofficials of affected small governmentsto have meaningful and timely input inthe development of EPA regulatoryproposals with significant Federalintergovernmental mandates, andinforming, educating, and advisingsmall governments on compliance withthe regulatory requirements.

EPA has determined that this ruledoes not contain a Federal mandate thatmay result in expenditures of $100million or more for State, local, andtribal governments, in the aggregate, orthe private sector in any one year. EPAprojects that the effect of the rule willbe a operational savings. EPA hasestimated this savings at $48.9 million(1999$, post-tax). Thus, today’s rule isnot subject to the requirements ofSections 202 and 205 of the UMRA.

EPA has determined that this rulecontains no regulatory requirements thatmight significantly or uniquely affectsmall governments. EPA projects that nosmall governments will be affected bythis rule as small governments are notengaged in oil and gas extractionoperations in offshore and coastalwaters or in issuing NPDES permits foroil and gas extraction operations inoffshore and coastal waters. Thus,today’s rule is not subject to therequirements of section 203 of theUMRA.

F. Executive Order 13084: Consultationand Coordination With Indian TribalGovernments

Under Executive Order 13084 EPAmay not issue a regulation that is notrequired by statute, that significantly oruniquely affects the communities ofIndian Tribal governments, and thatimposes substantial direct compliancecosts on those communities, unless theFederal government provides the fundsnecessary to pay the direct compliancecosts incurred by the tribalgovernments, or EPA consults withthose governments. If EPA complies byconsulting, Executive Order 13084requires EPA to provide to the Office ofManagement and Budget, in a separatelyidentified section of the preamble to therule, a description of the extent of EPA’sprior consultation with representativesof affected tribal governments, asummary of the nature of their concerns,and a statement supporting the need toissue the regulation. In addition,Executive Order 13084 requires EPA to

develop an effective process permittingelected officials and otherrepresentatives of Indian tribalgovernments ‘‘to provide meaningfuland timely input in the development ofregulatory policies on matters thatsignificantly or uniquely affect theircommunities.’’

Today’s rule does not significantly oruniquely affect the communities ofIndian tribal governments nor does itimpose substantial direct compliancecosts on them. EPA has determined thatcurrently, no communities of Indiantribal governments are affected by thisrule as Indian tribal governments are notengaged in oil and gas extractionoperations in offshore and coastalwaters or in issuing NPDES permits foroil and gas extraction operations inoffshore and coastal waters.Accordingly, the requirements ofsection 3(b) of Executive Order 13084do not apply to this rule.

G. Executive Order 13132: FederalismExecutive Order 13132, entitled

‘‘Federalism’’ (64 FR 43255, August 10,1999), requires EPA to develop anaccountable process to ensure‘‘meaningful and timely input by Stateand local officials in the development ofregulatory policies that have federalismimplications.’’ ‘‘Policies that havefederalism implications’’ is defined inthe Executive Order to includeregulations that have ‘‘substantial directeffects on the States, on the relationshipbetween the national government andthe States, or on the distribution ofpower and responsibilities among thevarious levels of government.’’

This final rule does not havefederalism implications. It will not havesubstantial direct effects on the States,on the relationship between the nationalgovernment and the States, or on thedistribution of power andresponsibilities among the variouslevels of government, as specified inExecutive Order 13132. The ruleestablishes effluent limitations andstandards imposing requirements thatapply to oil and gas extractionoperations in offshore and coastalwaters. EPA has determined that thereare no oil and gas extraction operationsin offshore and coastal waters that areowned and operated by State or localgovernments. Therefore, this rule willnot impose any requirements on State orlocal governments. Further, the rule willnot affect State governments’ authorityto implement CWA and UIC permittingprograms. In fact, the final rule mayreduce administrative costs on Statesthat have authorized NPDES programsbecause although these States mustincorporate the new limitations and



standards in new and revised NPDESpermits, they no longer will need tomake Best Professional Judgement (BPJ)determinations regarding theappropriate level of technology control.We recognize that there may be a smalladministrative cost to the State ofAlaska to assist EPA Region 10 indetermining whether Coastal Cook Inlet,Alaska, operators qualify for the SBF-cuttings zero discharge exemption (seeSection V.F). Thus, Executive Order13132 does not apply to this rule.

H. National Technology Transfer andAdvancement Act

As noted in the proposed rule (64 FR5528), section 12(d) of the NationalTechnology Transfer and AdvancementAct (NTTAA) of 1995, Pub L. 104–113section 12(d) (15 U.S.C. 272 note),directs EPA to use voluntary consensusstandards in its regulatory activitiesunless to do so would be inconsistentwith applicable law or otherwiseimpractical. Voluntary consensusstandards are technical standards (e.g.,materials specifications, test methods,sampling procedures, and businesspractices) that are developed or adoptedby voluntary consensus standard bodies.The NTTAA directs EPA to provideCongress, through the Office ofManagement and Budget (OMB),explanations when the Agency decidesnot to use available and applicablevoluntary consensus standards.

This rule involves technicalstandards. The rule requires dischargersto measure for two metals, PAH content(as phenanthrene), sediment toxicity,aqueous toxicity, biodegradation rate,formation oil content, and base fluidretained on cuttings. EPA performed asearch to identify potentially applicablevoluntary consensus standards thatcould be used to measure theparameters in today’s rule. EPA didlocate several voluntary consensusstandards that required modification forinclusion in the final rule. EPAconsidered public comments on theproposed rule and worked withstakeholders, including the industrysponsored Synthetic Based MudsResearch Consortium (SBMRC), tomodify or develop new standards forvarious parameters (i.e., sedimenttoxicity, biodegradation rate, PAHcontent (as phenanthrene), formation oilcontent, base fluid retained on cuttings).EPA has decided to use modifiedversions of the following voluntaryconsensus standards: (1) EPA Method1654A; (2) ASTM E–1367–92; (3) ISO11734:1995; and (4) API RecommendedPractice 13B–2. As indicated byindustry comments on the February1999 proposal and April 2000 NODA,

industry stakeholders support the use ofthese modified voluntary consensusstandards (see Docket No. W–98–26,Record No. IV.A.a.13).

I. Executive Order 13045: Protection ofChildren From Environmental HealthRisks and Safety Risks

The Executive Order 13045,‘‘Protection of Children fromEnvironmental Health Risks and SafetyRisks’’ (62 FR 19885, April 23, 1997),applies to any rule that: (1) Isdetermined to be ‘‘economicallysignificant’’ as defined under ExecutiveOrder 12866, and (2) concerns anenvironmental health or safety risk thatEPA has reason to believe may have adisproportionate effect on children. Ifthe regulatory action meets both criteria,the Agency must evaluate theenvironmental health or safety effects ofthe planned rule on children andexplain why the planned regulation ispreferable to other potentially effectiveand reasonably feasible alternativesconsidered by the Agency. This finalrule is not subject to E.O. 13045 becauseit is not ‘‘economically significant’’ asdefined under Executive Order 12866,and because the rule does not concernan environmental health or safety riskthat may have a disproportionate effecton children.

J. Executive Order 13158: MarineProtected Areas

Executive Order 13158 (65 FR 34909,May 31, 2000) requires EPA to‘‘expeditiously propose new science-based regulations, as necessary, toensure appropriate levels of protectionfor the marine environment.’’ EPA maytake action to enhance or expandprotection of existing marine protectedareas and to establish or recommend, asappropriate, new marine protectedareas. The purpose of the executiveorder is to protect the significant naturaland cultural resources within themarine environment, which means‘‘those areas of coastal and oceanwaters, the Great Lakes and theirconnecting waters, and submerged landsthereunder, over which the UnitedStates exercises jurisdiction, consistentwith international law.’’

EPA believes that this final rule isconsistent with the objectives of theExecutive Order to protect the oceanenvironment. By encouraging the use ofappropriately controlled SBFs in theplace of more toxic OBFs, the ocean willbe protected from the effects of spills ofOBFs and from the effects of disposal ofOBFs onshore. By encouraging the useof appropriately controlled SBFs overWBFs, there will much less drillingwaste generated and discharged to the

ocean per well and the drilling wastedischarged will be far less toxic and willbiodegrade at a much faster rate thanthose of traditional drilling fluids.

X. Regulatory ImplementationUpon promulgation of these

regulations, the effluent limitations forthe appropriate subcategory must beapplied in all Federal and State NPDESpermits issued to affected directdischargers in the oil and gas extractionindustry. This section discusses therelationship of upset and bypassprovisions, variances and modifications,and monitoring requirements.

A. Implementation of Limitations andStandards

Upon the promulgation of theseregulations, all new and reissuedFederal and State NPDES permits issuedto direct dischargers in the oil and gasextraction industry must include theeffluent limitations for the appropriatesubcategory. Permit writers should beaware that EPA has now finalizedrevisions to 40 CFR 122.44(a) whichcould be particularly relevant to thedevelopment of NPDES permits for theoil and gas extraction point sourcecategory (see 65 FR 30989, May 15,2000). As finalized, the revision wouldrequire that permits have limitations forall applicable guidelines-listedpollutants but allows for the waiver ofsampling requirements for guideline-listed pollutants on a case-by-case basisif the discharger can certify that thepollutant is not present in the dischargeor present in only background levelsfrom intake water with no increase dueto the activities of the dischargers. Newsources and new dischargers are noteligible for this waiver for their firstpermit term, and monitoring can be re-established through a minormodification if the discharger expandsor changes its process. Further, thepermittee must notify the permit writerof any modifications that have takenplace over the course of the permit termand, if necessary, monitoring can bereestablished through a minormodification.

B. Upset and Bypass ProvisionsA ‘‘bypass’’ is an intentional diversion

of waste streams from any portion of atreatment facility. An ‘‘upset’’ is anexceptional incident in which there isunintentional and temporarynoncompliance with technology-basedpermit effluent limitations because offactors beyond the reasonable control ofthe permittee. EPA’s regulationsconcerning bypasses and upsets are setforth at 40 CFR 122.41(m) and (n), and40 CFR 403.16 (upset) and 403.17



(bypass). The reader is also referred tothe Offshore Guidelines (58 FR 12501)for a discussion on upset and bypassprovisions.

C. Variances and ModificationsThe CWA requires application of the

effluent limitations and standardsestablished pursuant to section 301,304, 306, or the pretreatment standardsof section 307 to all direct and indirectdischargers. However, section 301(n)provides for the modification of thesenational requirements in a limitednumber of circumstances. Moreover, theAgency has established administrativemechanisms to provide an opportunityfor relief from the application ofnational effluent limitations guidelinesand pretreatment standards forcategories of existing sources forpriority, conventional and non-conventional pollutants (e.g.,fundamentally different factorvariances, removal credits).

The Fundamentally Different Factors(FDF) variances considers those facilityspecific factors which a permittee mayconsider to be uniquely different fromthose considered in the formulation ofan effluent limitations guidelines as tomake the limitation inapplicable. AnFDF variance must be based only oninformation submitted to EPA duringthe rulemaking establishing the effluentlimitations guidelines from which thevariance is being requested, or oninformation the applicant did not havea reasonable opportunity to submitduring the rulemaking process for theseeffluent limitations guidelines. FDFvariance requests must be received bythe permitting authority within 180days of publication of the final rule. Thespecific regulations covering therequirements for the administration ofFDF variances are found at 40 CFR122.21(m)(1), and 40 CFR part 125,subpart D.

D. Relationship of Effluent Limitationsto NPDES Permits and MonitoringRequirements

Effluent limitations act as a primarymechanism to control the discharges ofpollutants to waters of the UnitedStates. These limitations are applied toindividual facilities through NPDESpermits issued by EPA or authorizedStates under section 402 of the Act.

The Agency has developed thelimitations for this regulation to coverthe discharge of pollutants for thisindustrial category. In specific cases, theNPDES permitting authority may electto establish technology-based permitlimits for pollutants not covered by thisregulation. In addition, if State waterquality standards or other provisions of

State or Federal Law require limits onpollutants not covered by this regulation(or require more stringent limits oncovered pollutants), the permittingauthority must apply those limitations.

Working in conjunction with theeffluent limitations are the monitoringconditions set out in a NPDES permit.An integral part of the monitoringconditions is the point at which afacility must monitor to demonstratecompliance. The point at which asample is collected can have a dramaticeffect on the monitoring results for thatfacility. Therefore, it may be necessaryto require internal monitoring points inorder to ensure compliance. Authorityto address internal waste streams isprovided in 40 CFR 122.44(i)(1)(iii) and122.45(h). Permit writers may establishadditional internal monitoring points tothe extent consistent with EPA’sregulations.

An important component of themonitoring requirements established bythe permitting authority is the frequencyat which monitoring is required. Incosting the various technology optionsfor the oil and gas extraction industry,EPA assumed yearly SBF stocklimitations monitoring for mercury,cadmium, PAH (as phenanthrene),sediment toxicity, and biodegradationrates and daily or monthly monitoringfor diesel oil contamination, formationoil contamination, base fluid retainedon cuttings, aqueous toxicity, andsediment toxicity. These monitoringfrequencies may be lower than thosegenerally imposed by some permittingauthorities, but EPA believes thesereduced frequencies are appropriate dueto the relative costs of monitoring whencompared to the estimated costs ofcomplying with the promulgatedlimitations.

E. Analytical MethodsSection 304(h) of the Clean Water Act

directs EPA to promulgate guidelinesestablishing test procedures for theanalysis of pollutants. These testprocedures (methods) are used todetermine the presence andconcentration of pollutants inwastewater, and are used forcompliance monitoring and for filingapplications for the NPDES programunder 40 CFR 122.21, 122.41, 122.44and 123.25, and for the implementationof the pretreatment standards under 40CFR 403.10 and 403.12. To date, EPAhas promulgated methods forconventional pollutants, toxicpollutants, and for some non-conventional pollutants. The fiveconventional pollutants are defined at40 CFR 401.16. Table I–B at 40 CFR part136 lists the analytical methods

approved for these pollutants. The 65toxic metals and organic pollutants andclasses of pollutants are defined at 40CFR 401.15. From the list of 65 classesof toxic pollutants EPA identified a listof 126 ‘‘Priority Pollutants.’’ This list ofPriority Pollutants is shown, forexample, at 40 CFR part 423, AppendixA. The list includes non-pesticideorganic pollutants, metal pollutants,cyanide, asbestos, and pesticidepollutants.

Currently approved methods formetals and cyanide are included in thetable of approved inorganic testprocedures at 40 CFR 136.3, Table I–B.Table I–C at 40 CFR 136.3 lists approvedmethods for measurement of non-pesticide organic pollutants, and TableI–D lists approved methods for the toxicpesticide pollutants and for otherpesticide pollutants. Dischargers mustuse the test methods promulgated at 40CFR 136.3 or incorporated by referencein the tables, when available, to monitorpollutant discharges from the oil andgas industry, unless specified otherwisein part 435 or by the permittingauthority.

As part this rule, EPA is promulgatingthe use of analytical methods fordetermining additional parameters thatare specific to characterizing SBFs andother drilling fluids which do notdisperse in water. These additionalstock base fluid parameters includePAH content (as phenanthrene),sediment toxicity, and biodegradationrate. Additional discharge limitationsinclude prohibition of diesel oildischarge, formation (crude) oilcontamination, aqueous phase toxicity,sediment toxicity, and quantity ofdrilling fluid discharged with cuttings.

EPA worked with stakeholders toidentify methods for determining theseparameters. For PAH content (asphenanthrene), EPA is promulgating theuse of EPA Method 1654A. Forbiodegradation rate, EPA ispromulgating the use of the anaerobicclosed bottle biodegradation test (i.e.,ISO 11734:1995) as modified for themarine environment (i.e., Appendix 4 ofsubpart A of 40 CFR part 435). For basefluid sediment toxicity, EPA ispromulgating the use of the AmericanSociety for Testing and Material (ASTM)Method E–1367–92 supplemented withsediment preparation procedures (i.e.,Appendix 3 of subpart A of 40 CFR part435). For drilling fluid sedimenttoxicity, EPA is promulgating the use ofASTM Method E–1367–92supplemented with sedimentpreparation procedures (i.e., Appendix3 of subpart A of 40 CFR part 435) andreference drilling fluid preparationprocedures (i.e., Appendix 8 of subpart



A of 40 CFR part 435). For aqueoustoxicity, EPA is promulgating the use ofthe Suspended Particulate Phase (SPP)toxicity test (Appendix 2 of subpart Aof 40 CFR part 435). For formation(crude) oil contamination in drillingfluid, EPA is promulgating the use oftwo methods: a reverse phase extractionfluorescence test (RPE) and a gaschromatography/mass spectrometry(GC/MS) test. The RPE test (i.e.,Appendix 6 of subpart A of 40 CFR part435) is a screening method that providesa quick and inexpensive determinationof oil contamination for use on offshorewell drilling sites, while the GC/MS test(i.e., Appendix 5 of subpart A of 40 CFRpart 435) provides: (1) A definitiveidentification and quantification of oilcontamination for baseline analysis; and(2) confirmatory results for the RPEwhen the RPE results needconfirmation. For determining thequantity of drilling fluid dischargedwith cuttings, EPA is promulgating theuse of the American Petroleum Institute(API) Retort Method (RecommendedPractice 13B–2) with samplingprocedures (i.e., Appendix 7 of subpartA of 40 CFR part 435). For determiningwhen Coastal Cook Inlet, Alaska,operators qualify for an exemption fromthe Coastal requirement of zerodischarge for SBF-cuttings, EPA ispromulgating the use of the procedureoutlined in Appendix 1 of subpart D of40 CFR part 435.

EPA Method 1654A, ASTM E–1367–92, and ISO 11734:1995 areincorporated by reference into 40 CFRpart 435 because they are publishedmethods that are widely available to thepublic. Modifications to the anaerobicclosed bottle biodegradation test (i.e.,ISO 11734:1995) are provided inAppendix 4 of subpart A of 40 part 435.The SPP toxicity test is given inAppendix 2 of subpart A of 40 part 435.Supplemental sediment preparationprocedures for ASTM E–1367–92 areprovided in Appendix 3 of subpart A of40 CFR part 435. Reference drilling fluidpreparation procedures for ASTM E–1367–92 are provided in Appendix 8 ofsubpart A of 40 CFR part 435. The textof the GC/MS test, RPE test, and the APIretort method are provided inAppendices 5–7 of subpart A of 40 CFRpart 435. The procedure for determiningwhen Coastal Cook Inlet operatorsqualify for an exemption from theCoastal requirement of zero dischargefor SBF-cuttings is provided inAppendix 1 of subpart D of 40 CFR part435.

Appendix A to the Preamble—Abbreviations, Acronyms, and OtherTerms Used in This Preamble

Act—Clean Water ActAgency—U.S. Environmental Protection

AgencyAOGCC—Alaska Oil and Gas Conservation

CommissionAPI—American Petroleum InstituteANL—Argonne National Laboratory (DOE)ASTM—American Society of Testing and

MaterialsBADCT—The best available demonstrated

control technology, for new sourcesunder section 306 of the Clean WaterAct.

BAT—The best available technologyeconomically achievable, under section304(b)(2)(B) of the Clean Water Act.

bbl—barrel, 42 U.S. gallonsBCT—Best conventional pollutant control

technology under section 304(b)(4)(B).BMP—Best management practices under

section 304(e) of the Clean Water Act.BOD—Biochemical oxygen demand.BOE—Barrels of oil equivalentBPJ—Best Professional JudgementBPT—Best practicable control technology

currently available, under section304(b)(1) of the Clean Water Act.

CERCLA—Comprehensive EnvironmentalResponse, Compensation, and LiabilityAct

CFR—U.S. Code of Federal RegulationsClean Water Act—Federal Water Pollution

Control Act Amendments of 1972 asamended (33 U.S.C. 1251 et seq)

Conventional pollutants—Constituents ofwastewater as determined by section304(a)(4) of the Act, including, but nolimited to, pollutants classified asbiochemical oxygen demanding,suspended solids, oil and grease, fecalcoliform, and pH

Direct discharger—A facility whichdischarges or may discharge pollutantsto waters of the United States

D&B—Dun & BradstreetDOE—U.S. Department of EnergyDWD—Deep-water development model wellDWE—Deep-water exploratory model wellEMO—Enhanced Mineral Oil Drilling FluidEPA—U.S. Environmental Protection AgencyFR—Federal RegisterGC—Gas ChromatographyGC/FID—Gas Chromatography with Flame

Ionization DetectionGC/MS—Gas Chromatography with Mass

Spectroscopy DetectionGOM—Gulf of MexicoIndirect discharger—A facility that

introduces wastewater into a publiclyowned treatment works.

IRFA—Initial Regulatory Flexibility AnalysisLC50 (or LC50)—The concentration of a test

material that is lethal to 50% of the testorganisms in a bioassay

mg/l—milligrams per literMMS—U.S. Department of Interior, Minerals

Management ServiceNAF—Non-Aqueous Drilling Fluid (includes

OBFs, EMOs, and SBFs)Non-conventional pollutants—Pollutants that

have not been designated as eitherconventional pollutants or prioritypollutants

NODA—Notice of Data Availability (65 FR21548; April 21, 2000)

NOIA—National Ocean IndustriesAssociation

NOW—Nonhazardous Oilfield WasteNPDES—National Pollutant Discharge

Elimination SystemNRDC—Natural Resources Defense Council,

Inc.NSPS—New source performance standards

under section 306 of the Clean Water ActNTTAA—National Technology Transfer and

Advancement ActNWQI—Non-Water Quality Environmental

ImpactsOBF—Oil-Based Drilling FluidOCS—Outer Continental ShelfOMB—Office of Management and BudgetPAH—Polynuclear Aromatic HydrocarbonPDC—Polycrystalline Diamond Compact

(drill bit)POTW—Publicly Owned Treatment Works

ppm—parts per millionPPA—Pollution Prevention Act of 1990Priority pollutants—The 65 pollutants and

classes of pollutants declared toxicunder section 307(a) of the Clean WaterAct

PSES—Pretreatment standards for existingsources of indirect discharges, undersection 307(b) of the Act

PSNS—Pretreatment standards for newsources of indirect discharges, undersections 307(b) and (c) of the Act

RFA—Regulatory Flexibility ActROC—Retention on CuttingsRPE—Reverse Phase ExtractionSBA—U.S. Small Business AdministrationSBF—Synthetic Based Drilling FluidSBF Development Document—Development

Document for Final Effluent LimitationsGuidelines and Standards for Synthetic-Based Drilling Fluids and other Non-Aqueous Drilling Fluids in the Oil andGas Extraction Point Source Category(EPA–821–B–00–013)

SBF Economic Analysis—Economic Analysisof Final Effluent Limitations Guidelinesand Standards for Synthetic-BasedDrilling Fluids and other Non-AqueousDrilling Fluids in the Oil and GasExtraction Point Source Category (EPA–821–B–00–012)

SBF Environmental Assessment—Environmental Assessment of FinalEffluent Limitations Guidelines andStandards for Synthetic-Based DrillingFluids and other Non-Aqueous DrillingFluids in the Oil and Gas ExtractionPoint Source Category (EPA–821–B–00–014)

SBF Statistical Support Document—Statistical Analyses Supporting FinalEffluent Limitations Guidelines andStandards for Synthetic-Based DrillingFluids and other Non-Aqueous DrillingFluids in the Oil and Gas ExtractionPoint Source Category (EPA–821–B–00–015)

SBMRC—Synthetic Based Muds ResearchConsortium

SBREFA—Small Business RegulatoryEnforcement Fairness Act

SIC—Standard Industrial ClassificationSPP—Suspended Particulate Phase toxicity

test (Appendix 2 to Subpart A of 40 CFR435)



SWD—Shallow-water development modelwell

SWE—Shallow-water exploratory model wellTSS—Total Suspended SolidsUMRA—Unfunded Mandates Reform ActUIC—Underground Injection Control

programs of the Safe Drinking Water Actof 1974 as amended

U.S.C.—United States CodeWBF—Water-Based Drilling Fluid

List of Subjects

40 CFR Part 9Reporting and recordkeeping

requirements.

40 CFR Part 435

Environmental protection, Non-aqueous drilling fluids, Oil and gasextraction, Pollution prevention,Synthetic based drilling fluids, Wastetreatment and disposal, Water non-dispersible drilling fluids, Waterpollution control.

Dated: December 28, 2000.Carol M. Browner,Administrator.

For the reasons set forth in thispreamble, 40 CFR parts 9 and 435 areamended as follows:

PART 9—OMB APPROVALS UNDERTHE PAPERWORK REDUCTION ACT

1. The authority citation for part 9continues to read as follows:

Authority: 7 U.S.C. 135 et seq., 136–136y;15 U.S.C. 2001, 2003, 2005, 2006, 2601–2671;21 U.S.C. 331j, 346a, 348; 31 U.S.C. 9701; 33U.S.C. 1251 et seq., 1311, 1313d, 1314, 1318,1321, 1326, 1330, 1342, 1344, 1345 (d) and(e), 1361; E.O. 11735, 38 FR 21243, 3 CFR,1971–1975 Comp. p. 973; 42 U.S.C. 241,242b, 243, 246, 300f, 300g, 300g–1, 300g–2,300g–3, 300g–4, 300g–5, 300g–6, 300j–1,300j–2, 300j–3, 300j–4, 300j–9, 1857 et seq.,6901–6992k, 7401–7671q, 7542, 9601–9657,11023, 11048.

2. In § 9.1 the table is amended byadding entries in numerical order undera new heading titled ‘‘Oil and GasExtraction Point Source Category’’ toread as follows:

§ 9.1 OMB approvals under the PaperworkReduction Act.

* * * * *

40 CFR citation OMB controlNo.

* * * * *Oil and Gas Extraction Point

Source Category:435.13 ................................ 2040–0230435.15 ................................ 2040–0230435.43 ................................ 2040–0230

40 CFR citation OMB controlNo.

435.45 ................................ 2040–0230

* * * * *

PART 435—OIL 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, 1342 and 1361.

Subpart A—Offshore Subcategory

2. Section 435.11 is amended byrevising paragraphs (b) through (cc) andby adding paragraphs (dd) through (tt)to read as follows:

§ 435.11 Special definitions.

* * * * *(b) Average of daily values for 30

consecutive days means the average ofthe daily values obtained during any 30consecutive day period.

(c) Base fluid means the continuousphase or suspending medium of adrilling fluid formulation.

(d) Base fluid retained on cuttings asapplied to BAT effluent limitations andNSPS refers to the American PetroleumInstitute Recommended Practice 13B–2supplemented with the specifications,sampling methods, and averagingmethod for retention values provided inAppendix 7 of Subpart A of this part.

(e) Biodegradation rate as applied toBAT effluent limitations and NSPS fordrilling fluids and drill cuttings refers tothe ISO 11734:1995 method: ‘‘Waterquality—Evaluation of the ‘ultimate’anaerobic biodegradability of organiccompounds in digested sludge—Methodby measurement of the biogasproduction (1995 edition)’’supplemented with modifications inAppendix 4 of 40 CFR part 435, subpartA. This incorporation by reference wasapproved by the Director of the FederalRegister in accordance with 5 U.S.C.552(a) and 1 CFR part 51. Copies maybe obtained from the American NationalStandards Institute, 11 West 42ndStreet, 13th Floor, New York, NY 10036.Copies may be inspected at the Office ofthe Federal Register, 800 North CapitolStreet, NW., Suite 700, Washington, DC.A copy may also be inspected at EPA’sWater Docket, 401 M Street SW.,Washington, DC 20460.

(f) Daily values as applied toproduced water effluent limitations andNSPS means the daily measurements

used to assess compliance with themaximum for any one day.

(g) Deck drainage means any wasteresulting from deck washings, spillage,rainwater, and runoff from gutters anddrains including drip pans and workareas within facilities subject to thisSubpart.

(h) Development facility means anyfixed or mobile structure subject to thissubpart that is engaged in the drilling ofproductive wells.

(i) Diesel oil refers to the grade ofdistillate fuel oil, as specified in theAmerican Society for Testing andMaterials Standard Specification forDiesel Fuel Oils D975–91, that istypically used as the continuous phasein conventional oil-based drilling fluids.This incorporation by reference wasapproved by the Director of the FederalRegister in accordance with 5 U.S.C.552(a) and 1 CFR part 51. Copies maybe obtained from the American Societyfor Testing and Materials, 100 BarrHarbor Drive, West Conshohocken, PA,19428. Copies may be inspected at theOffice of the Federal Register, 800North Capitol Street, NW., Suite 700,Washington, DC. A copy may also beinspected at EPA’s Water Docket, 401 MStreet SW., Washington, DC 20460.

(j) Domestic waste means materialsdischarged from sinks, showers,laundries, safety showers, eye-washstations, hand-wash stations, fishcleaning stations, and galleys locatedwithin facilities subject to this Subpart.

(k) Drill cuttings means the particlesgenerated by drilling into subsurfacegeologic formations and carried outfrom the wellbore with the drillingfluid. Examples of drill cuttings includesmall pieces of rock varying in size andtexture from fine silt to gravel. Drillcuttings are generally generated fromsolids control equipment and settle outand accumulate in quiescent areas inthe solids control equipment or otherequipment processing drilling fluid (i.e.,accumulated solids).

(1) Wet drill cuttings means theunaltered drill cuttings and adheringdrilling fluid and formation oil carriedout from the wellbore with the drillingfluid.

(2) Dry drill cuttings means theresidue remaining in the retort vesselafter completing the retort procedurespecified in appendix 7 of subpart A ofthis part.

(l) Drilling fluid means the circulatingfluid (mud) used in the rotary drillingof wells to clean and condition the holeand to counterbalance formationpressure. Classes of drilling fluids are:

(1) Water-based drilling fluid meansthe continuous phase and suspending



medium for solids is a water-misciblefluid, regardless of the presence of oil.

(2) Non-aqueous drilling fluid meansthe continuous phase and suspendingmedium for solids is a water-immisciblefluid, such as oleaginous materials (e.g.,mineral oil, enhanced mineral oil,paraffinic oil, C16–C18 internal olefins,and C8–C16 fatty acid/2-ethylhexylesters).

(i) Oil-based means the continuousphase of the drilling fluid consists ofdiesel oil, mineral oil, or some other oil,but contains no synthetic material orenhanced mineral oil.

(ii) Enhanced mineral oil-basedmeans the continuous phase of thedrilling fluid is enhanced mineral oil.

(iii) Synthetic-based means thecontinuous phase of the drilling fluid isa synthetic material or a combination ofsynthetic materials.

(m) Enhanced mineral oil as appliedto enhanced mineral oil-based drillingfluid means a petroleum distillatewhich has been highly purified and isdistinguished from diesel oil andconventional mineral oil in having alower polycyclic aromatic hydrocarbon(PAH) content. Typically, conventionalmineral oils have a PAH content on theorder of 0.35 weight percent expressedas phenanthrene, whereas enhancedmineral oils typically have a PAHcontent of 0.001 or lower weight percentPAH expressed as phenanthrene.

(n) Exploratory facility means anyfixed or mobile structure subject to thisSubpart that is engaged in the drillingof wells to determine the nature ofpotential hydrocarbon reservoirs.

(o) Formation oil means the oil froma producing formation which is detectedin the drilling fluid, as determined bythe GC/MS compliance assurancemethod specified in appendix 5 ofsubpart A of this part when the drillingfluid is analyzed before being shippedoffshore, and as determined by the RPEmethod specified in appendix 6 ofsubpart A of this part when the drillingfluid is analyzed at the offshore point ofdischarge. Detection of formation oil bythe RPE method may be confirmed bythe GC/MS compliance assurancemethod, and the results of the GC/MScompliance assurance method shallsupercede those of the RPE method.

(p) M9IM means those offshorefacilities continuously manned by nine(9) or fewer persons or onlyintermittently manned by any numberof persons.

(q) M10 means those offshore facilitiescontinuously manned by ten (10) ormore persons.

(r) Maximum as applied to BATeffluent limitations and NSPS fordrilling fluids and drill cuttings means

the maximum concentration allowed asmeasured in any single sample of thebarite for determination of cadmiumand mercury content.

(s) Maximum for any one day asapplied to BPT, BCT and BAT effluentlimitations and NSPS for oil and greasein produced water means the maximumconcentration allowed as measured bythe average of four grab samplescollected over a 24-hour period that areanalyzed separately. Alternatively, forBAT and NSPS the maximumconcentration allowed may bedetermined on the basis of physicalcomposition of the four grab samplesprior to a single analysis.

(t) Maximum weighted mass ratioaveraged over all NAF well sections forBAT effluent limitations and NSPS forbase fluid retained on cuttings meansthe weighted average base fluidretention for all NAF well sections asdetermined by the API RecommendedPractice 13B–2, using the methods andaveraging calculations presented inAppendix 7 of subpart A of this part.

(u) Method 1654A refers to Method1654, Revision A, entitled ‘‘PAHContent of Oil by HPLC/UV,’’ December1992, which is published in Methods forthe Determination of Diesel, Mineral,and Crude Oils in Offshore Oil and GasIndustry Discharges, EPA–821–R–92–008. This incorporation by referencewas approved by the Director of theFederal Register in accordance with 5U.S.C. 552(a) and 1 CFR part 51. Copiesmay be obtained from the NationalTechnical Information Service,Springfield, VA 22161, 703–605–6000.Copies may be inspected at the Office ofthe Federal Register, 800 North CapitolStreet, NW., Suite 700, Washington, DC.A copy may also be inspected at EPA’sWater Docket, 401 M Street SW.,Washington, DC 20460.

(v) Minimum as applied to BATeffluent limitations and NSPS fordrilling fluids and drill cuttings meansthe minimum 96-hour LC50 valueallowed as measured in any singlesample of the discharged waste stream.Minimum as applied to BPT and BCTeffluent limitations and NSPS forsanitary wastes means the minimumconcentration value allowed asmeasured in any single sample of thedischarged waste stream.

(w)(1) New source means any facilityor activity of this subcategory that meetsthe definition of ‘‘new source’’ under 40CFR 122.2 and meets the criteria fordetermination of new sources under 40CFR 122.29(b) applied consistently withall of the following definitions:

(i) Water area as used in ‘‘site’’ in 40CFR 122.29 and 122.2 means the waterarea and water body floor beneath any

exploratory, development, orproduction facility where such facilityis conducting its exploratory,development or production activities.

(ii) Significant site preparation workas used in 40 CFR 122.29 means theprocess of surveying, clearing orpreparing an area of the water bodyfloor for the purpose of constructing orplacing a development or productionfacility 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.

(x) No discharge of free oil means thatwaste streams may not be dischargedthat contain free oil as evidenced by themonitoring method specified for thatparticular stream, e.g., deck drainage ormiscellaneous discharges cannot bedischarged when they would cause afilm or sheen upon or discoloration ofthe surface of the receiving water;drilling fluids or cuttings may not bedischarged when they fail the staticsheen test defined in Appendix 1 ofsubpart A of this part.

(y) Parameters that are regulated inthis Subpart and listed with approvedmethods of analysis in Table 1B at 40CFR 136.3 are defined as follows:

(1) Cadmium means total cadmium.(2) Chlorine means total residual

chlorine.(3) Mercury means total mercury.(4) Oil and Grease means total

recoverable oil and grease.(z) PAH (as phenanthrene) means

polynuclear aromatic hydrocarbonsreported as phenanthrene.

(aa) Produced sand means the slurriedparticles used in hydraulic fracturing,the accumulated formation sands andscales particles generated duringproduction. Produced sand alsoincludes desander discharge from theproduced water waste stream, andblowdown of the water phase from theproduced water treating system.

(bb) Produced water means the water(brine) brought up from thehydrocarbon-bearing strata during theextraction of oil and gas, and caninclude formation water, injectionwater, and any chemicals addeddownhole or during the oil/waterseparation process.

(cc) Production facility means anyfixed or mobile structure subject to thisSubpart that is either engaged in wellcompletion or used for active recoveryof hydrocarbons from producingformations.

(dd) Sanitary waste means the humanbody waste discharged from toilets and



urinals located within facilities subjectto this Subpart.

(ee) Sediment toxicity as applied toBAT effluent limitations and NSPS fordrilling fluids and drill cuttings refers tothe ASTM E 1367–92 method:‘‘Standard Guide for Conducting 10-dayStatic Sediment Toxicity Tests withMarine and Estuarine Amphipods,’’1992, with Leptocheirus plumulosus asthe test organism and sedimentpreparation procedures specified inAppendix 3 of 40 CFR part 435, subpartA. This incorporation by reference wasapproved by the Director of the FederalRegister in accordance with 5 U.S.C.552(a) and 1 CFR part 51. Copies maybe obtained from the American Societyfor Testing and Materials, 100 BarrHarbor Drive, West Conshohocken, PA,19428. Copies may be inspected at theOffice of the Federal Register, 800 NorthCapitol Street, NW., Suite 700,Washington, DC. A copy may also beinspected at EPA’s Water Docket, 401 MStreet SW., Washington, DC 20460.

(ff) Solids control equipment meansshale shakers, centrifuges, mudcleaners, and other equipment used toseparate drill cuttings and/or stockbarite solids from drilling fluidrecovered from the wellbore.

(gg) SPP toxicity as applied to BATeffluent limitations and NSPS fordrilling fluids and drill cuttings refers tothe bioassay test procedure presented inAppendix 2 of subpart A of this part.

(hh) Static sheen test means thestandard test procedure that has beendeveloped 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 of subpart A of this part.

(ii) Stock barite means the barite thatwas used to formulate a drilling fluid.

(jj) Stock base fluid means the basefluid that was used to formulate adrilling fluid.

(kk) Synthetic material as applied tosynthetic-based drilling fluid meansmaterial produced by the reaction ofspecific purified chemical feedstock, asopposed to the traditional base fluidssuch as diesel and mineral oil which arederived from crude oil solely throughphysical separation processes. Physicalseparation processes includefractionation and distillation and/orminor chemical reactions such as

cracking and hydro processing. Sincethey are synthesized by the reaction ofpurified compounds, synthetic materialssuitable for use in drilling fluids aretypically free of polycyclic aromatichydrocarbons (PAH’s) but aresometimes found to contain levels ofPAH up to 0.001 weight percent PAHexpressed as phenanthrene. Internalolefins and vegetable esters are twoexamples of synthetic materials suitablefor use by the oil and gas extractionindustry in formulating drilling fluids.Internal olefins are synthesized from theisomerization of purified straight-chain(linear) hydrocarbons such as C16–C18

linear alpha olefins. C16–C18 linear alphaolefins are unsaturated hydrocarbonswith the carbon to carbon double bondin the terminal position. Internal olefinsare typically formed from heating linearalpha olefins with a catalyst. The feedmaterial for synthetic linear alphaolefins is typically purified ethylene.Vegetable esters are synthesized fromthe acid-catalyzed esterification ofvegetable fatty acids with variousalcohols. EPA listed these two branchesof synthetic fluid base materials toprovide examples, and EPA does notmean to exclude other syntheticmaterials that are either in current useor may be used in the future. Asynthetic-based drilling fluid mayinclude a combination of syntheticmaterials.

(ll) Well completion fluids means saltsolutions, weighted brines, polymers,and various additives used to preventdamage to the well bore duringoperations which prepare the drilledwell for hydrocarbon production.

(mm) Well treatment fluids means anyfluid used to restore or improveproductivity by chemically orphysically altering hydrocarbon-bearingstrata after a well has been drilled.

(nn) Workover fluids means saltsolutions, weighted brines, polymers, orother specialty additives used in aproducing well to allow formaintenance, repair or abandonmentprocedures.

(oo) 4-day LC50 as applied to thesediment toxicity BAT effluentlimitations and NSPS means theconcentration (milligrams/kilogram drysediment) of the drilling fluid insediment that is lethal to 50 percent ofthe Leptocheirus plumulosus testorganisms exposed to that concentration

of the drilling fluids after four days ofconstant exposure.

(pp) 10-day LC50 as applied to thesediment toxicity BAT effluentlimitations and NSPS means theconcentration (milligrams/kilogram drysediment) of the base fluid in sedimentthat is lethal to 50 percent of theLeptocheirus plumulosus test organismsexposed to that concentration of thebase fluids after ten days of constantexposure.

(qq) 96-hour LC50 means theconcentration (parts per million) orpercent 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.

(rr) C16–C18 internal olefin means a65/35 blend, proportioned by mass, ofhexadecene and octadecene,respectively. Hexadecene is anunsaturated hydrocarbon with a carbonchain length of 16, an internal doublecarbon bond, and is represented by theChemical Abstracts Service (CAS) No.26952–14–7. Octadecene is anunsaturated hydrocarbon with a carbonchain length of 18, an internal doublecarbon bond, and is represented by theChemical Abstracts Service (CAS) No.27070–58–2. (Properties available fromthe Chemical Abstracts Service, 2540Olentangy River Road, PO Box 3012,Columbus, OH, 43210).

(ss) C16–C18 internal olefin drillingfluid means a C16–C18 internal olefindrilling fluid formulated as specified inAppendix 8 of subpart A of this part.

(tt) C12–C14 ester and C8 ester meansthe fatty acid/2-ethylhexyl esters withcarbon chain lengths ranging from 8 to16 and represented by the ChemicalAbstracts Service (CAS) No. 135800–37–2. (Properties available from theChemical Abstracts Service, 2540Olentangy River Road, PO Box 3012,Columbus, OH, 43210)

3. In § 435.12 the table is amended byremoving the entries ‘‘Drilling muds’’and ‘‘Drill cuttings’’ and by adding newentries (after ‘‘Deck drainage’’) for‘‘Water based’’ and ‘‘Non-aqueous’’ toread as follows:

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

* * * * *



BPT EFFLUENT LIMITATIONS—OIL AND GREASE

[In milligrams per liter]

Pollutant parameter waste source Maximum for any 1 day Average of values for 30 con-secutive days shall not exceed

Residualchlorineminimumfor any 1

day

* * * * * * *Water-based:

Drilling fluids .......................................................................... (1) .............................................. (1) .............................................. NADrill Cuttings .......................................................................... (1) .............................................. (1) .............................................. NA

Non-aqueous:Drilling fluids .......................................................................... No discharge ............................. No discharge ............................. NADrill Cuttings .......................................................................... (1) .............................................. (1) .............................................. NA

* * * * * * *

1 No discharge of free oil.

* * * * *

4. In § 435.13 the table is amended by revising entry (B) under ‘‘Drilling fluids and drill cuttings’’ and by revisingfootnote 2 and adding footnotes 5–11 to read as follows:

§ 435.13 Effluent limitations guidelines representing the degree of effluent reduction attainable by the application of the best availabletechnology economically achievable (BAT).

* * * * *

BAT EFFLUENT LIMITATIONS

Waste source Pollutant parameter BAT effluent limitation

* * * * * * *Drilling fluids and drill cuttings:

* * * * * * *(B) For facilities located beyond 3

miles from shore:Water-based drilling fluids and

associated drill cuttings.SPP Toxicity .................................. Minimum 96-hour LC50 of the SPP Toxicity Test 2 shall be 3% by vol-

ume.Free oil ........................................... No discharge.3Diesel oil ........................................ No discharge.Mercury .......................................... 1 mg/kg dry weight maximum in the stock barite.Cadmium ........................................ 3 mg/kg dry weight maximum in the stock barite.

Non-aqueous drilling fluids(NAFs).

........................................................ No discharge.

Drill cuttings associated with non-aqueous drilling fluids:

Stock Limitations (C16–C18 in-ternal olefin).

Mercury .......................................... 1 mg/kg dry weight maximum in the stock barite.

Cadmium ........................................ 3 mg/kg dry weight maximum in the stock barite.Polynuclear Aromatic Hydro-

carbons (PAH).PAH mass ratio 5 shall not exceed 1x10¥5.

Sediment toxicity ............................ Base fluid sediment toxicity ratio 6 shall not exceed 1.0.Biodegradation rate ....................... Biodegradation rate ratio 7 shall not exceed 1.0.

Discharge Limitations ............. Diesel oil ........................................ No discharge.SPP Toxicity .................................. Minimum 96-hour LC50 of the SPP Toxicity Test 2 shall be 3% by vol-

ume.Sediment toxicity ............................ Drilling fluid sediment toxicity ratio 8 shall not exceed 1.0.Formation Oil ................................. No discharge.9Base fluid retained on cuttings ...... For NAFs that meet the stock limitations (C16–C18 internal olefin) in

this table, the maximum weighted mass ratio averaged over all NAFwell sections shall be 6.9 g-NAF base fluid/100 g-wet drillcuttings.10

For NAFs that meet the C12–C14 ester or C8 ester stock limitations infootnote 11 of this table, the maximum weighted mass ratio aver-aged over all NAF well sections shall be 9.4 g-NAF base fluid/100g-wet drill cuttings.



BAT EFFLUENT LIMITATIONS—Continued


* * * * * * *

* * * * * * *2 As determined by the suspended particulate phase (SPP) toxicity test (Appendix 2 of subpart A of this part).3 As determined by the static sheen test (Appendix 1 of subpart A of this part).* * * * * * *5 PAH mass ratio = Mass (g) of PAH (as phenanthrene)/Mass (g) of stock base fluid as determined by EPA Method 1654, Revision A, (speci-

fied at § 435.11(u)) entitled ‘‘PAH Content of Oil by HPLC/UV,’’ December 1992, which is published in Methods for the Determination of Diesel,Mineral, and Crude Oils in Offshore Oil and Gas Industry Discharges, EPA–821–R–92–008. This incorporation by reference was approved by theDirector of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies may be obtained from the National Technical In-formation Service, Springfield, VA 22161, 703–605–6000. Copies may be inspected at the Office of the Federal Register, 800 North CapitolStreet, NW., Suite 700, Washington, DC. A copy may also be inspected at EPA’s Water Docket, 401 M Street SW., Washington, DC 20460.

6 Base fluid sediment toxicity ratio = 10-day LC50 of C16–C18 internal olefin/10-day LC50 of stock base fluid as determined by ASTM E 1367–92[specified at § 435.11(ee)] method: ‘‘Standard Guide for Conducting 10-day Static Sediment Toxicity Tests with Marine and EstuarineAmphipods,’’ 1992, after preparing the sediment according to the method specified in Appendix 3 of subpart A of this part. This incorporation byreference was approved by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies may be obtainedfrom the American Society for Testing and Materials, 100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies may be inspected at theOffice of the Federal Register, 800 North Capitol Street, NW., Suite 700, Washington, DC. A copy may also be inspected at EPA’s Water Dock-et, 401 M Street SW., Washington, DC 20460.

7 Biodegradation rate ratio = Cumulative gas production (ml) of C16–C18 internal olefin/Cumulative gas production (ml) of stock base fluid, bothat 275 days as determined by ISO 11734:1995 [specified at § 435.11(e)] method: ‘‘Water quality—Evaluation of the ‘ultimate’ anaerobicbiodegradability of organic compounds in digested sludge—Method by measurement of the biogas production (1995 edition)’’ as modified for themarine environment (Appendix 4 of subpart A of this part). This incorporation by reference was approved by the Director of the Federal Registerin accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies may be obtained from the American National Standards Institute, 11 West 42ndStreet, 13th Floor, New York, NY 10036. Copies may be inspected at the Office of the Federal Register, 800 North Capitol Street, NW., Suite700, Washington, DC. A copy may also be inspected at EPA’s Water Docket, 401 M Street SW., Washington, DC 20460.

8 Drilling fluid sediment toxicity ratio = 4-day LC50 of C16–C18 internal olefin drilling fluid/4-day LC50 of drilling fluid removed from drill cuttings atthe solids control equipment as determined by ASTM E 1367–92 (specified at § 435.11(ee)) method: ‘‘Standard Guide for Conducting 10-dayStatic Sediment Toxicity Tests with Marine and Estuarine Amphipods,’’ 1992, after preparing the sediment according to the method specified inAppendix 3 of subpart A of this part. This incorporation by reference was approved by the Director of the Federal Register in accordance with 5U.S.C. 552(a) and 1 CFR part 51. Copies may be obtained from the American Society for Testing and Materials, 100 Barr Harbor Drive, WestConshohocken, PA, 19428. Copies may be inspected at the Office of the Federal Register, 800 North Capitol Street, NW., Suite 700, Wash-ington, DC. A copy may also be inspected at EPA’s Water Docket, 401 M Street SW., Washington, DC 20460.

9 As determined before drilling fluids are shipped offshore by the GC/MS compliance assurance method (Appendix 5 of subpart A of this part),and as determined prior to discharge by the RPE method (Appendix 6 of subpart A of this part) applied to drilling fluid removed from drillcuttings. If the operator wishes to confirm the results of the RPE method (Appendix 6 of subpart A of this part), the operator may use the GC/MScompliance assurance method (Appendix 5 of subpart A of this part). Results from the GC/MS compliance assurance method (Appendix 5 ofsubpart A of this part) shall supercede the results of the RPE method (Appendix 6 of subpart A of this part).

10 Maximum permissible retention of non-aqueous drilling fluid (NAF) base fluid on wet drill cuttings averaged over drilling intervals using NAFsas determined by the API retort method (Appendix 7 of subpart A of this part). This limitation is applicable for NAF base fluids that meet the basefluid sediment toxicity ratio (Footnote 6), biodegradation rate ratio (Footnote 7), PAH, mercury, and cadmium stock limitations (C16–C18 internalolefin) defined above in this table.

11 Maximum permissible retention of non-aqueous drilling fluid (NAF) base fluid on wet drill cuttings average over drilling intervals using NAFsas determined by the API retort method (Appendix 7 of subpart A of this part). This limitation is applicable for NAF base fluids that meet the esterbase fluid sediment toxicity ratio and ester biodegradation rate ratio stock limitations defined as: (a) ester base fluid sediment toxicity ratio = 10-day LC50 of C12–C14 ester or C8 ester /10-day LC50 of stock base fluid as determined by ASTM E 1367–92 (specified at § 435.11(ee)) method:‘‘Standard Guide for Conducting 10-day Static Sediment Toxicity Tests with Marine and Estuarine Amphipods,’’ 1992, after preparing the sedi-ment according to the method specified in Appendix 3 of subpart A of this part. This incorporation by reference was approved by the Director ofthe Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies may be obtained from the American Society for Testing andMaterials, 100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies may be inspected at the Office of the Federal Register, 800 NorthCapitol Street, NW., Suite 700, Washington, DC. A copy may also be inspected at EPA’s Water Docket, 401 M Street SW., Washington, DC20460. (b) ester biodegradation rate ratio = Cumulative gas production (ml) of C12–C14 ester or C8 ester/Cumulative gas production (ml) of stockbase fluid, both at 275 days as determined by ISO 11734:1995 (specified at § 435.11(e)) method: ‘‘Water quality—Evaluation of the ‘ultimate’ an-aerobic biodegradability of organic compounds in digested sludge—Method by measurement of the biogas production (1995 edition)’’ as modifiedfor the marine environment (Appendix 4 of subpart A of this part). This incorporation by reference was approved by the Director of the FederalRegister in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies may be obtained from the American National Standards Institute, 11West 42nd Street, 13th Floor, New York, NY 10036. Copies may be inspected at the Office of the Federal Register, 800 North Capitol Street,NW., Suite 700, Washington, DC. A copy may also be inspected at EPA’s Water Docket, 401 M Street SW., Washington, DC 20460. (c) PAHmass ratio (Footnote 5), mercury, and cadmium stock limitations (C16–C18 internal olefin) defined above in this table.

5. In § 435.14 the table is amended by revising entry (B) under ‘‘Drilling fluids and drill cuttings’’ to read asfollows:

§ 435.14 Effluent limitations guidelines representing the degree of effluent reduction attainable by the application of the bestconventional pollutant control technology (BCT).

* * * * *

BCT EFFLUENT LIMITATIONS

Waste source Pollutant parameter BCT effluent limita-tion




BCT EFFLUENT LIMITATIONS—Continued


* * * * * * *(B) For facilities located beyond 3 miles from shore:

Water-based drilling fluids and associated drill cuttings Free Oil ................................................................................... No discharge.2

Non-aqueous drilling fluids .............................................. ................................................................................................. No discharge.Drill cuttings associated with non-aqueous drilling fluids Free Oil ................................................................................... No discharge.2

* * * * * * *2 As determined by the static sheen test (Appendix 1 of Subpart A of this part).* * * * * * *

6. In § 435.15 the table is amended by revising entry (B) under ‘‘Drilling fluids and drill cuttings’’ and by revisingfootnote 2 and adding footnotes 5–11 to read as follows:

§ 435.15 Standards of performance for new sources (NSPS).

* * * * *

NEW SOURCE PERFORMANCE STANDARDS (NSPS)

Waste source Pollutant parameter NSPS


* * * * * * *(B) For facilities located beyond 3

miles from shore:Water-based drilling fluids and

associated drill cuttings.SPP Toxicity .................................. Minimum 96-hour LC50 of the SPP Toxicity Test 2 shall be 3% by vol-

ume.Free oil ........................................... No discharge.3Diesel oil ........................................ No charge.Mercury .......................................... 1mg/kg dry weight maximum in the stock barite.Cadmium ........................................ 3 mg/kg dry weight maximum in the stock barite.

Non-aqueous drilling fluids ..... ........................................................ No charge.Drill cuttings associated with non-

aqueous drilling fluids:Stock Limitations (C16–C18 in-

ternal olefin.Mercury .......................................... 1mg/kg dry weight maximum in the stock barite.

Cadmium ........................................ 3 mg/kg dry weight maximum in the stock barite.Polynuclear Aromatic Hydro-

carbons (PAH).PAH mass ratio5 shall not exceed 1×10¥5

Sediment toxicity ............................ Base fluid sediment toxicity ratio 6 shall not exceed 1.0.Biodegradation rate ....................... Biodegradation rate ratio7 shall not exceed 1.0.

Discharge Limitations ............. Diesel oil ........................................ No discharge.SPP Toxicity .................................. Minimum 96-hour LC50 of the SPP Toxicity Test 2 shall be 3% by vol-

ume.Sediment toxicity ............................ Drilling fluid sediment toxicity ratio 8 shall not exceed 1.0.Formation Oil ................................. No discharge.9Base fluid retained on cuttings ...... For NAFs that meet the stock limitations (C16–C18 internal olefin) in

this table, the maximum weighted mass ratio averaged over all NAFwell sections shall be 6.9 g–NAF base fluid/100 g-wet drillcuttings.10

For NAFs that meet the C12–C14 ester or C8 ester stock limitations infootnote 11 of this table, the maximum weighted mass ratio aver-aged over all NAF well sections shall be 9.4 g–NAF base fluid/100g-wet drill cuttings.

* * * * * * *

* * * * * * *2 As determined by the suspended particulate phase (SPP) toxicity test (Appendix 2 of subpart A of this part).3 As determined by the static sheen test (appendix 1 of subpart A of this part).* * * * * * *5 PAH mass ratio = Mass (g) of PAH (as phenanthrene)/Mass (g) of stock base fluid as determined by EPA Method 1654, Revision A, (speci-

fied at § 435.11(u)) entitled ‘‘PAH Content of Oil by HPLC/UV,’’ December 1992, which is published in Methods for the Determination of Diesel,Mineral, and Crude Oils in Offshore Oil and Gas Industry Discharges, EPA–821–R–92–008. This incorporation by reference was approved by theDirector of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies may be obtained from the National Technical In-formation Service, Springfield, VA 22161, 703–605–6000. Copies may be inspected at the Office of the Federal Register, 800 North CapitolStreet, NW., Suite 700, Washington, DC. A copy may also be inspected at EPA’s Water Docket, 401 M Street SW., Washington, DC 20460.



6 Base fluid sediment toxicity ratio = 10-day LC50 of C16–C18 internal olefin/10-day LC50 of stock base fluid as determined by ASTM E 1367–92(specified at § 435.11(ee)) method: ‘‘Standard Guide for Conducting 10-day Static Sediment Toxicity Tests with Marine and EstuarineAmphipods,’’ 1992, after preparing the sediment according to the method specified in Appendix 3 of subpart A of this part. This incorporation byreference was approved by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies may be obtainedfrom the American Society for Testing and Materials, 100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies may be inspected at theOffice of the Federal Register, 800 North Capitol Street, NW., Suite 700, Washington, DC. A copy may also be inspected at EPA’s Water Dock-et, 401 M Street SW., Washington, DC 20460.

7 Biodegradation rate ratio = Cumulative gas production (ml) of C16–C18 internal olefin/Cumulative gas production (ml) of stock base fluid, bothat 275 days as determined by ISO 11734:1995 (specified at § 435.11(e)) method: ‘‘Water quality—Evaluation of the ‘ultimate’ anaerobicbiodegradability of organic compounds in digested sludge—Method by measurement of the biogas production (1995 edition)’’ as modified for themarine environment (Appendix 4 of subpart A of this part). This incorporation by reference was approved by the Director of the Federal Registerin accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies may be obtained from the American National Standards Institute, 11 West 42ndStreet, 13th Floor, New York, NY 10036. Copies may be inspected at the Office of the Federal Register, 800 North Capitol Street, NW., Suite700, Washington, DC. A copy may also be inspected at EPA’s Water Docket, 401 M Street SW., Washington, DC 20460.

8 Drilling fluid sediment toxicity ratio = 4-day LC50 of C16–C18 internal olefin drilling fluid/4-day LC50 of drilling fluid removed from drill cuttings atthe solids control equipment as determined by ASTM E 1367–92 (specified at § 435.11(ee)) method: ‘‘Standard Guide for Conducting 10-dayStatic Sediment Toxicity Tests with Marine and Estuarine Amphipods,’’ 1992, after preparing the sediment according to the method specified inAppendix 3 of subpart A of this part. This incorporation by reference was approved by the Director of the Federal Register in accordance with 5U.S.C. 552(a) and 1 CFR part 51. Copies may be obtained from the American Society for Testing and Materials, 100 Barr Harbor Drive, WestConshohocken, PA, 19428. Copies may be inspected at the Office of the Federal Register, 800 North Capitol Street, NW., Suite 700, Wash-ington, DC. A copy may also be inspected at EPA’s Water Docket, 401 M Street SW., Washington, DC 20460.

9 As determined before drilling fluids are shipped offshore by the GC/MS compliance assurance method (Appendix 5 of subpart A of this part),and as determined prior to discharge by the RPE method (Appendix 6 of subpart A of this part) applied to drilling fluid removed from drillcuttings. If the operator wishes to confirm the results of the RPE method (Appendix 6 of subpart A of this part), the operator may use the GC/MScompliance assurance method (Appendix 5 of subpart A of this part). Results from the GC/MS compliance assurance method (Appendix 5 ofsubpart A of this part) shall supercede the results of the RPE method (Appendix 6 of subpart A of this part).

10 Maximum permissible retention of non-aqueous drilling fluid (NAF) base fluid on wet drill cuttings averaged over drilling intervals using NAFsas determined by the API retort method (Appendix 7 of subpart A of this part). This limitation is applicable for NAF base fluids that meet the basefluid sediment toxicity ratio (Footnote 6), biodegradation rate ratio (Footnote 7), PAH, mercury, and cadmium stock limitations (C16–C18 internalolefin) defined above in this table.

11 Maximum permissible retention of non-aqueous drilling fluid (NAF) base fluid on wet drill cuttings average over drilling intervals using NAFsas determined by the API retort method (Appendix 7 of subpart A of this part). This limitation is applicable for NAF base fluids that meet the esterbase fluid sediment toxicity ratio and ester biodegradation rate ratio stock limitations defined as: (a) Ester base fluid sediment toxicity ratio = 10-day LC50 of C12–C14 ester or C8 ester /10-day LC50 of stock base fluid as determined by ASTM E 1367–92 [specified at § 435.11(ee)] method:‘‘Standard Guide for Conducting 10-day Static Sediment Toxicity Tests with Marine and Estuarine Amphipods,’’ 1992, after preparing the sedi-ment according to the method specified in Appendix 3 of subpart A of this part. This incorporation by reference was approved by the Director ofthe Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies may be obtained from the American Society for Testing andMaterials, 100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies may be inspected at the Office of the Federal Register, 800 NorthCapitol Street, NW., Suite 700, Washington, DC. A copy may also be inspected at EPA’s Water Docket, 401 M Street SW., Washington, DC20460; (b) Ester biodegradation rate ratio = Cumulative gas production (ml) of C12–C14 ester or C8 ester/Cumulative gas production (ml) of stockbase fluid, both at 275 days as determined by ISO 11734:1995 (specified at § 435.11(e)) method: ‘‘Water quality—Evaluation of the ‘ultimate’ an-aerobic biodegradability of organic compounds in digested sludge—Method by measurement of the biogas production (1995 edition)’’ as modifiedfor the marine environment (Appendix 4 of subpart A of this part). This incorporation by reference was approved by the Director of the FederalRegister in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies may be obtained from the American National Standards Institute, 11West 42nd Street, 13th Floor, New York, NY 10036. Copies may be inspected at the Office of the Federal Register, 800 North Capitol Street,NW., Suite 700, Washington, DC. A copy may also be inspected at EPA’s Water Docket, 401 M Street SW., Washington, DC 20460; and (c)PAH mass ratio (Footnote 5), mercury, and cadmium stock limitations (C16–C18 internal olefin) defined above in this table.

7. Subpart A of this part is amendedby adding Appendices 3 through 8 asfollows:

Appendix 3 to Subpart A of Part 435—Procedure for Mixing Base Fluids withSediments

This procedure describes a method foramending uncontaminated and nontoxic(control) sediments with the base fluids thatare used to formulate synthetic-based drillingfluids and other non-aqueous drilling fluids.Initially, control sediments shall be press-sieved through a 2000 micron mesh sieve toremove large debris. Then press-sieve thesediment through a 500 micron sieve toremove indigenous organisms that may preyon the test species or otherwise confound testresults. Homogenize control sediment tolimit the effects of settling that may haveoccurred during storage. Sediments shouldbe homogenized before densitydeterminations and addition of base fluid tocontrol sediment. Because base fluids arestrongly hydrophobic and do not readily mixwith sediment, care must be taken to ensurebase fluids are thoroughly homogenizedwithin the sediment. All concentrations areweight-to-weight (mg of base fluid to kg ofdry control sediment). Sediment and basefluid mixing shall be accomplished by usingthe following method.

1. Determine the wet to dry ratio for thecontrol sediment by weighing approximately10 g subsamples of the screened andhomogenized wet sediment into taredaluminum weigh pans. Dry sediment at 105°C for 18–24 h. Remove sediment and coolin a desiccator until a constant weight isachieved. Re-weigh the samples to determinethe dry weight. Determine the wet/dry ratioby dividing the net wet weight by the net dryweight:[Wet Sediment Weight (g)]/[Dry Sediment

Weight (g)] = Wet to Dry Ratio [1]2. Determine the density (g/mL) of the wet

control or dilution sediment. This shall beused to determine total volume of wetsediment needed for the various testtreatments.[Mean Wet Sediment Weight (g)]/[Mean Wet

Sediment Volume (mL)] = Wet SedimentDensity (g/mL) [2]

3. To determine the amount of base fluidneeded to obtain a test concentration of 500mg base fluid per kg dry sediment use thefollowing formulas:

Determine the amount of wet sedimentrequired:[Wet Sediment Density (g/mL)] × [Volume of

Sediment Required per Concentration(mL)] = Weight Wet Sediment Requiredper Conc. (g) [3]

Determine the amount of dry sediment inkilograms (kg) required for eachconcentration:{[Wet Sediment per Concentration (g)]/[Mean

Wet to Dry Ratio]} × (1kg/1000g) = DryWeight Sediment (kg) [4]

Finally, determine the amount of base fluidrequired to spike the control sediment ateach concentration:[Conc. Desired (mg/kg)] × [Dry Weight

Sediment (kg)] = Base Fluid Required(mg) [5]

For spiking test substances other than purebase fluids (e.g., whole mud formulations),determine the spike amount as follows:[Conc. Desired (mL/kg)] × [Dry Weight

Sediment (kg)] × [Test Substance Density(g/mL)] = Test Substance Required (g)[6]

4. For primary mixing, place appropriateamounts of weighed base fluid into stainlessmixing bowls, tare the vessel weight, thenadd sediment and mix with a high-sheardispersing impeller for 9 minutes. Theconcentration of base fluid in sediment fromthis mix, rather than the nominalconcentration, shall be used in calculatingLC50 values.

5. Tests for homogeneity of base fluid insediment are to be performed during theprocedure development phase. Because of



difficulty of homogeneously mixing basefluid with sediment, it is important todemonstrate that the base fluid is evenlymixed with sediment. The sediment shall beanalyzed for total petroleum hydrocarbons(TPH) using EPA Methods 3550A and8015M, with samples taken both prior to andafter distribution to replicate test containers.Base-fluid content is measured as TPH. Aftermixing the sediment, a minimum of threereplicate sediment samples shall be takenprior to distribution into test containers.After the test sediment is distributed to testcontainers, an additional three sedimentsamples shall be taken from three testcontainers to ensure proper distribution ofbase fluid within test containers. Base-fluidcontent results shall be reported within 48hours of mixing. The coefficient of variation(CV) for the replicate samples must be lessthan 20%. If base-fluid content results are notwithin the 20% CV limit, the test sedimentshall be remixed. Tests shall not begin untilthe CV is determined to be below themaximum limit of 20%. During the test, aminimum of three replicate containers shallbe sampled to determine base-fluid contentduring each sampling period.

6. Mix enough sediment in this way toallow for its use in the preparation of all testconcentrations and as a negative control.When commencing the sediment toxicitytest, range-finding tests may be required todetermine the concentrations that produce atoxic effect if these data are otherwiseunavailable. The definitive test shall bracketthe LC50, which is the desired endpoint. Theresults for the base fluids shall be reportedin mg of base fluid per kg of dry sediment.

References

American Society for Testing and Materials(ASTM). 1996. Standard Guide forCollection, Storage, Characterization, andManipulation of Sediments for ToxicologicalTesting. ASTM E 1391–94. Annual Book ofASTM Standards, Volume 11.05, pp. 805–825.

Ditsworth, G.R., D.W. Schults and J.K.P.Jones. 1990. Preparation of benthic substratesfor sediment toxicity testing, Environ.Toxicol. Chem. 9:1523–1529.

Suedel, B.C., J.H. Rodgers, Jr. and P.A.Clifford. 1993. Bioavailability of fluoranthenein freshwater sediment toxicity tests.Environ. Toxicol. Chem. 12:155–165.

U.S. EPA. 1994. Methods for Assessing theToxicity of Sediment-associatedContaminants with Estuarine and MarineAmphipods. EPA/600/R–94/025. Office ofResearch and Development, Washington, DC.

Appendix 4 to Subpart A of Part 435—Determination of Biodegradation ofSynthetic Base Fluids in a Marine ClosedBottle Test System: Summary ofModifications to ISO 11734:1995

The six modifications specified in thisAppendix shall apply to the determination ofthe biodegradability of synthetic base fluidsas measured by ISO 11734:1995. Thesemodifications make the test more applicableto a marine environment and are listedbelow:

1. The laboratory shall use sea water inplace of freshwater media.

1.1 The sea water may be either naturalor synthetic. The allowable salinity range is20–30 ppt.

1.2 To reduce the shock to themicroorganisms in the sediment, the salinityof the sediment’s porewater shall be between20–30 ppt.

2. The laboratory shall use natural marineor estuarine sediments in place of digestedsludge as an inoculum. The VS of thesediments must be no less than 2%.

2.1 Sediment should be used for testingas soon as possible after field collection. Ifrequired, the laboratory can store thesediment for a maximum period of twomonths prior to use. The test sediment shallbe stored in the dark at 4°C.

2.2 The laboratory shall use the sedimentmixing procedure specified in Appendix 3 toSubpart A of part 435 to spike the testsediment with base fluids. The finalconcentration will be 2000 mg carbon/Kg dryweight sediment. No less than 25 g dryweight of the spiked sediment shall be usedper 125 ml serum bottle. The volume ofsediment and seawater in the bottle shall be75 ml.

3. The temperature of incubation shall be29±1°C.

4. The pH is maintained at the level ofnatural sea water, not at 7.0 as referenced inISO 11734:1995.

5. The optional use of a trace metalssolution as specified in method ISO11734:1995 shall not be used as part of thesetest modifications.

6. The laboratory shall conduct the testfor 275 days. The laboratory may seekapproval of alternate test durations under theapproval procedures specified at 40 CFR136.4 and 136.5. Any modification of thismethod, beyond those expressly permitted,shall be considered a major modificationsubject to application and approval ofalternate test procedures under 40 CFR 136.4and 136.5.

Appendix 5 to Subpart A of Part 435—Determination of Crude Oil Contaminationin Non-Aqueous Drilling Fluids by GasChromatography/Mass Spectrometry (GC/MS)

1.0 Scope and Application1.1 This method determines crude

(formation) oil contamination, or otherpetroleum oil contamination, in non-aqueousdrilling fluids (NAFs) by comparing the gaschromatography/mass spectrometry (GC/MS)fingerprint scan and extracted ion scans ofthe test sample to that of an uncontaminatedsample.

1.2 This method can be used formonitoring oil contamination of NAFs ormonitoring oil contamination of the basefluid used in the NAF formulations.

1.3 Any modification of this methodbeyond those expressly permitted shall beconsidered as a major modification subject toapplication and approval of alternative testprocedures under 40 CFR 136.4 and 136.5.

1.4 The gas chromatography/massspectrometry portions of this method arerestricted to use by, or under the supervisionof analysts experienced in the use of GC/MSand in the interpretation of gaschromatograms and extracted ion scans. Each

laboratory that uses this method mustgenerate acceptable results using theprocedures described in Sections 7, 9.2, and12 of this appendix.

2.0 Summary of Method

2.1 Analysis of NAF for crude oilcontamination is a step-wise process. Theanalyst first performs a qualitativeassessment of the presence or absence ofcrude oil in the sample. If crude oil isdetected during this qualitative assessment,the analyst must perform a quantitativeanalysis of the crude oil concentration.

2.2 A sample of NAF is centrifuged toobtain a solids free supernate.

2.3 The test sample is prepared byremoving an aliquot of the solids freesupernate, spiking it with internal standard,and analyzing it using GC/MS techniques.The components are separated by the gaschromatograph and detected by the massspectrometer.

2.4 Qualitative identification of crude oilcontamination is performed by comparingthe Total Ion Chromatograph (TIC) scans andExtracted Ion Profile (EIP) scans of testsample to that of uncontaminated base fluids,and examining the profiles forchromatographic signatures diagnostic of oilcontamination.

2.5 The presence or absence of crude oilcontamination observed in the full scanprofiles and selected extracted ion profilesdetermines further sample quantitation andreporting requirements.

2.6 If crude oil is detected in thequalitative analysis, quantitative analysismust be performed by calibrating the GC/MSusing a designated NAF spiked with knownconcentrations of a designated oil.

2.7 Quality is assured throughreproducible calibration and testing of GC/MS system and through analysis of qualitycontrol samples.

3.0 Definitions

3.1 A NAF is one in which thecontinuous— phase is a water immisciblefluid such as an oleaginous material (e.g.,mineral oil, enhance mineral oil, paraffinicoil, or synthetic material such as olefins andvegetable esters).

3.2 TIC—Total Ion Chromatograph.3.3 EIP—Extracted Ion Profile.3.4 TCB—1,3,5-trichlorobenzene is used

as the internal standard in this method.3.5 SPTM—System Performance Test Mix

standards are used to establish retentiontimes and monitor detection levels.

4.0 Interferences and Limitations

4.1 Solvents, reagents, glassware, andother sample processing hardware may yieldartifacts and/or elevated baselines causingmisinterpretation of chromatograms.

4.2 All Materials used in the analysisshall be demonstrated to be free frominterferences by running method blanks.Specific selection of reagents andpurification of solvents by distillation in all-glass systems may be required.

4.3 Glassware shall be cleaned by rinsingwith solvent and baking at 400 °C for aminimum of 1 hour.



4.4 Interferences may vary from source tosource, depending on the diversity of thesamples being tested.

4.5 Variations in and additions of basefluids and/or drilling fluid additives(emulsifiers, dispersants, fluid loss controlagents, etc.) might also cause interferencesand misinterpretation of chromatograms.

4.6 Difference in light crude oils, mediumcrude oils, and heavy crude oils will resultin different responses and thus differentinterpretation of scans and calculatedpercentages.

5.0 Safety5.1 The toxicity or carcinogenicity of

each reagent used in this method has notbeen precisely determined; however eachchemical shall be treated as a potential healthhazard. Exposure to these chemicals shouldbe reduced to the lowest possible level.

5.2 Unknown samples may contain highconcentration of volatile toxic compounds.Sample containers should be opened in ahood and handled with gloves to preventexposure. In addition, all sample preparationshould be conducted in a fume hood to limitthe potential exposure to harmfulcontaminates.

5.3 This method does not address allsafety issues associated with its use. Thelaboratory is responsible for maintaining asafe work environment and a currentawareness file of OSHA regulations regardingthe safe handling of the chemicals specifiedin this method. A reference file of materialsafety data sheets (MSDSs) shall be availableto all personnel involved in these analyses.Additional references to laboratory safety canbe found in References 16.1 through 16.3.

5.4 NAF base fluids may cause skinirritation, protective gloves are recommendedwhile handling these samples.

6.0 Apparatus and Materials

Note: Brand names, suppliers, and partnumbers are for illustrative purposes only.No endorsement is implied. Equivalentperformance may be achieved usingapparatus and materials other than thosespecified here, but demonstration ofequivalent performance meeting therequirements of this method is theresponsibility of the laboratory.

6.1 Equipment for glassware cleaning.6.1.1 Laboratory sink with overhead fume

hood.6.1.2 Kiln—Capable of reaching 450 °C

within 2 hours and holding 450 °C within±10 °C, with temperature controller andsafety switch (Cress Manufacturing Co., SantaFe Springs, CA B31H or X31TS orequivalent).

6.2 Equipment for sample preparation.6.2.1 Laboratory fume hood.6.2.2 Analytical balance—Capable of

weighing 0.1 mg.6.2.3 Glassware.6.2.3.1 Disposable pipettes—Pasteur, 150

mm long by 5 mm ID (Fisher Scientific 13–678–6A, or equivalent) baked at 400 °C for aminimum of 1 hour.

6.2.3.2 Glass volumetric pipettes or gastight syringes—1.0-mL ± 1% and 0.5-mL ±1%.

6.2.3.3 Volumetric flasks—Glass, class A,10-mL, 50-mL and 100-mL.

6.2.3.4—Sample vials—Glass, 1- to 3-mL(baked at 400 °C for a minimum of 1 hour)with PTFE-lined screw or crimp cap.

6.2.3.5 Centrifuge and centrifuge tubes—Centrifuge capable of 10,000 rpm, or better,(International Equipment Co., IEC CentraMP4 or equivalent) and 50-mL centrifugetubes (Nalgene, Ultratube, Thin Wall 25×89mm, #3410–2539).

6.3 Gas Chromatograph/MassSpectrometer (GC/MS):

6.3.1 Gas Chromatograph—An analyticalsystem complete with a temperature-programmable gas chromatograph suitable forsplit/splitless injection and all requiredaccessories, including syringes, analyticalcolumns, and gases.

6.3.1.1 Column—30 m (or 60 m) × 0.32mm ID (or 0.25 mm ID) 1µm film thickness(or 0.25µm film thickness) silicone-coatedfused-silica capillary column (J&W ScientificDB–5 or equivalent).

6.3.2 Mass Spectrometer—Capable ofscanning from 35 to 500 amu every 1 sec orless, using 70 volts (nominal) electron energyin the electron impact ionization mode(Hewlett Packard 5970MS or comparable).

6.3.3 GC/MS interface—the interface is acapillary-direct interface from the GC to theMS.

6.3.4—Data system—A computer systemmust be interfaced to the mass spectrometer.The system must allow the continuousacquisition and storage on machine-readablemedia of all mass spectra obtainedthroughout the duration of thechromatographic program. The computermust have software that can search any GC/MS data file for ions of a specific mass andthat can plot such ion abundance versusretention time or scan number. This type ofplot is defined as an Extracted Ion CurrentProfile (EIP). Software must also be availablethat allows integrating the abundance in anytotal ion chromatogram (TIC) or EIP betweenspecified retention time or scan-numberlimits. It is advisable that the most recentversion of the EPA/NIST Mass SpectralLibrary be available.

7.0 Reagents and Standards

7.1 Methylene chloride—Pesticide gradeor equivalent. Use when necessary for sampledilution.

7.2 Standards—Prepare from pureindividual standard materials or purchase ascertified solutions. If compound purity is96% or greater, the weight may be usedwithout correction to compute theconcentration of the standard.

7.2.1 Crude Oil Reference—Obtain asample of a crude oil with a known APIgravity. This oil shall be used in thecalibration procedures.

7.2.2 Synthetic Base Fluid—Obtain asample of clean internal olefin (IO) Labdrilling fluid (as sent from the supplier—hasnot been circulated downhole). This drillingfluid shall be used in the calibrationprocedures.

7.2.3 Internal standard—Prepare a 0.01 g/mL solution of 1,3,5-trichlorobenzene (TCB).Dissolve 1.0 g of TCB in methylene chlorideand dilute to volume in a 100-mL volumetricflask. Stopper, vortex, and transfer thesolution to a 150-mL bottle with PTFE-lined

cap. Label appropriately, and store at –5 °Cto 20 °C. Mark the level of the meniscus onthe bottle to detect solvent loss.

7.2.4 GC/MS system performance test mix(SPTM) standards—The SPTM standardsshall contain octane, decane, dodecane,tetradecane, tetradecene, toluene,ethylbenzene, 1,2,4-trimethylbenzene, 1-methylnaphthalene and 1,3-dimethylnaphthalene. These compounds canbe purchased individually or obtained as amixture (i.e. Supelco, Catalog No. 4–7300).Prepare a high concentration of the SPTMstandard at 62.5 mg/mL in methylenechloride. Prepare a medium concentrationSPTM standard at 1.25 mg/mL by transferring1.0 mL of the 62.5 mg/mL solution into a 50mL volumetric flask and diluting to the markwith methylene chloride. Finally, prepare alow concentration SPTM standard at 0.125mg/mL by transferring 1.0 mL of the 1.25 mg/mL solution into a 10-mL volumetric flaskand diluting to the mark with methylenechloride.

7.2.5 Crude oil/drilling fluid calibrationstandards—Prepare a 4-point crude oil/drilling fluid calibration at concentrations of0% (no spike—clean drilling fluid), 0.5%,1.0%, and 2.0% by weight according to theprocedures outlined in this appendix usingthe Reference Crude Oil:

7.2.5.1 Label 4 jars with the followingidentification: Jar 1—0%Ref-IOLab, Jar 2—0.5%Ref-IOLab, Jar 3—1%Ref-IOLab, and Jar4—2%Ref-IOLab.

7.2.5.2 Weigh 4, 50-g aliquots of wellmixed IO Lab drilling fluid into each of the4 jars.

7.2.5.3 Add Reference Oil at 0.5%, 1.0%,and 2.0% by weight to jars 2, 3, and 4respectively. Jar 1 shall not be spiked withReference Oil in order to retain a ‘‘0%’’ oilconcentration.

7.2.5.4 Thoroughly mix the contents ofeach of the 4 jars, using clean glass stirringrods.

7.2.5.5 Transfer (weigh) a 30-g aliquotfrom Jar 1 to a labeled centrifuge tube.Centrifuge the aliquot for a minimum of 15min at approximately 15,000 rpm, in order toobtain a solids free supernate. Weigh 0.5 g ofthe supernate directly into a tared andappropriately labeled GC straight vial. Spikethe 0.5-g supernate with 500 µL of the 0.01g/mL 1,3,5-trichlorobenzene internal standardsolution (see Section 7.2.3 of this appendix),cap with a Teflon lined crimp cap, andvortex for ca. 10 sec.

7.2.5.6 Repeat step 7.2.5.5 except use analiquot from Jar 2.



7.2.5.9 These 4 crude/oil drilling fluidcalibration standards are now used forqualitative and quantitative GC/MS analysis.

7.2.6 Precision and recovery standard(mid level crude oil/drilling fluid calibrationstandard)—Prepare a mid point crude oil/drilling fluid calibration using IO Lab drillingfluid and Reference Oil at a concentration of1.0% by weight. Prepare this standardaccording to the procedures outlined inSection 7.2.5.1 through 7.2.5.5 of thisappendix, with the exception that only ‘‘Jar



3’’ needs to be prepared. Remove and spikewith internal standard, as many 0.5-galiquots as needed to complete the GC/MSanalysis (see Section 11.6 of this appendix—bracketing authentic samples every 12 hourswith precision and recovery standard) andthe initial demonstration exercise describedin Section 9.2 of this appendix.

7.2.7 Stability of standards7.2.7.1 When not used, standards shall be

stored in the dark, at ¥5 to ¥20 °C in screw-capped vials with PTFE-lined lids. Place amark on the vial at the level of the solutionso that solvent loss by evaporation can bedetected. Bring the vial to room temperatureprior to use.

7.2.7.2 Solutions used for quantitativepurposes shall be analyzed within 48 hoursof preparation and on a monthly basisthereafter for signs of degradation. Astandard shall remain acceptable if the peakarea remains within ±15% of the areaobtained in the initial analysis of thestandard.

8.0 Sample Collection Preservation andStorage

8.1 Collect NAF and base fluid samplesin 100- to 200-mL glass bottles with PTFE-or aluminum foil lined caps.

8.2 Samples collected in the field shall bestored refrigerated until time of preparation.

8.3 Sample and extract holding times forthis method have not yet been established.However, based on initial experience withthe method, samples should be analyzedwithin seven to ten days of collection andextracts should be analyzed within sevendays of preparation.

8.4 After completion of GC/MS analysis,extracts shall be refrigerated at 4 °C untilfurther notification of sample disposal.

9.0 Quality Control9.1 Each laboratory that uses this method

is required to operate a formal qualityassurance program (Reference 16.4). Theminimum requirements of this program shallconsist of an initial demonstration oflaboratory capability, and ongoing analysis ofstandards, and blanks as a test of continuedperformance, analyses of spiked samples toassess accuracy and analysis of duplicates toassess precision. Laboratory performanceshall be compared to establishedperformance criteria to determine if theresults of analyses meet the performancecharacteristics of the method.

9.1.1 The analyst shall make an initialdemonstration of the ability to generateacceptable accuracy and precision with thismethod. This ability shall be established asdescribed in Section 9.2 of this appendix.

9.1.2 The analyst is permitted to modifythis method to improve separations or lowerthe cost of measurements, provided allperformance requirements are met. Each timea modification is made to the method, theanalyst is required to repeat the calibration(Section 10.4 of this appendix) and to repeatthe initial demonstration proceduredescribed in Section 9.2 of this appendix.

9.1.3 Analyses of blanks are required todemonstrate freedom from contamination.The procedures and criteria for analysis of ablank are described in Section 9.3 of thisappendix.

9.1.4 Analysis of a matrix spike sample isrequired to demonstrate method accuracy.The procedure and QC criteria for spiking aredescribed in Section 9.4 of this appendix.

9.1.5 Analysis of a duplicate field sampleis required to demonstrate method precision.The procedure and QC criteria for duplicatesare described in Section 9.5 of this appendix.

9.1.6 Analysis of a sample of the cleanNAF(s) (as sent from the supplier—i.e., hasnot been circulated downhole) used in thedrilling operations is required.

9.1.7 The laboratory shall, on an ongoingbasis, demonstrate through calibrationverification and the analysis of the precisionand recovery standard (Section 7.2.6 of thisappendix) that the analysis system is incontrol. These procedures are described inSection 11.6 of this appendix.

9.1.8 The laboratory shall maintainrecords to define the quality of data that isgenerated.

9.2 Initial precision and accuracy—Theinitial precision and recovery test shall beperformed using the precision and recoverystandard (1% by weight Reference Oil in IOLab drilling fluid). The laboratory shallgenerate acceptable precision and recoveryby performing the following operations.

9.2.1 Prepare four separate aliquots of theprecision and recovery standard using theprocedure outlined in Section 7.2.6 of thisappendix. Analyze these aliquots using theprocedures outlined in Section 11 of thisappendix.

9.2.2 Using the results of the set of fouranalyses, compute the average recovery (X) inweight percent and the standard deviation ofthe recovery(s) for each sample.

9.2.3 If s and X meet the acceptancecriteria of 80% to 110%, system performanceis acceptable and analysis of samples maybegin. If, however, s exceeds the precisionlimit or X falls outside the range for accuracy,system performance is unacceptable. In thisevent, review this method, correct theproblem, and repeat the test.

9.2.4 Accuracy and precision—Theaverage percent recovery (P) and the standarddeviation of the percent recovery (Sp)Express the accuracy assessment as a percentrecovery interval from P–2Sp to P+2Sp. Forexample, if P=90% and Sp=10% for fouranalyses of crude oil in NAF, the accuracyinterval is expressed as 70% to 110%.Update the accuracy assessment on a regularbasis.

9.3 Blanks—Rinse glassware andcentrifuge tubes used in the method with 30mL of methylene chloride, remove a 0.5-galiquot of the solvent, spike it with the 500µL of the internal standard solution (Section7.2.3 of this appendix) and analyze a 1-µLaliquot of the blank sample using theprocedure in Section 11 of this appendix.Compute results per Section 12 of thisappendix.

9.4 Matrix spike sample—Prepare amatrix spike sample according to procedureoutlined in Section 7.2.6 of this appendix.Analyze the sample and calculate theconcentration (% oil) in the drilling fluid and% recovery of oil from the spiked drillingfluid using the methods described inSections 11 and 12 of this appendix.

9.5 Duplicates—A duplicate field sampleshall be prepared according to procedures

outlined in Section 7.3 of this appendix andanalyzed according to Section 11 of thisappendix. The relative percent difference(RPD) of the calculated concentrations shallbe less than 15%.

9.5.1 Analyze each of the duplicates perthe procedure in Section 11 of this appendixand compute the results per Section 12 ofthis appendix.

9.5.2 Calculate the relative percentdifference (RPD) between the two results perthe following equation:RPD = [D1 ¥ D2]/[(D1 + D2)/2] × 100 [1]

where:D1 = Concentration of crude oil in the

sample; andD2 = Concentration of crude oil in the

duplicate sample.

9.5.3 If the RPD criteria are not met, theanalytical system shall be judged to be out ofcontrol, and the problem must beimmediately identified and corrected, andthe sample batch re-analyzed.

9.6 Prepare the clean NAF sampleaccording to procedures outlined in Section7.3 of this appendix. Ultimately the oil-equivalent concentration from the TIC or EIPsignal measured in the clean NAF sampleshall be subtracted from the correspondingauthentic field samples in order to calculatethe true contaminant concentration (% oil) inthe field samples (see Section 12 of thisappendix).

9.7 The specifications contained in thismethod can be met if the apparatus used iscalibrated properly, and maintained in acalibrated state. The standards used forinitial precision and recovery (Section 9.2 ofthis appendix) and ongoing precision andrecovery (Section 11.6 of this appendix) shallbe identical, so that the most precise resultswill be obtained. The GC/MS instrument willprovide the most reproducible results ifdedicated to the setting and conditionsrequired for the analyses given in thismethod.

9.8 Depending on specific programrequirements, field replicates and field spikesof crude oil into samples may be requiredwhen this method is used to assess theprecision and accuracy of the sampling andsample transporting techniques.

10.0 Calibration10.1 Establish gas chromatographic/mass

spectrometer operating conditions given inTable 1 of this appendix. Perform the GC/MSsystem hardware-tune as outlined by themanufacture. The gas chromatograph shall becalibrated using the internal standardtechnique.

Note: Because each GC is slightly different,it may be necessary to adjust the operatingconditions (carrier gas flow rate and columntemperature and temperature program)slightly until the retention times in Table 2of this appendix are met.

TABLE 1.—GAS CHROMATOGRAPH/MASS SPECTROMETER (GC/MS)OPERATION CONDITIONS

Parameter Setting

Injection pot ............... 280 °C



TABLE 1.—GAS CHROMATOGRAPH/MASS SPECTROMETER (GC/MS)OPERATION CONDITIONS—Contin-ued

Parameter Setting

Transfer line .............. 280 °CDetector ..................... 280 °CInitial Temperature .... 50 °CInitial Time ................. 5 minutesRamp ......................... 50 to 300 °C @ 5 °C

per minuteFinal Temperature ..... 300 °CFinal Hold .................. 20 minutes or until all

peaks have elutedCarrier Gas ............... HeliumFlow rate ................... As required for stand-

ard operationSplit ratio ................... As required to meet

performance cri-teria (∼1:100)

Mass range ............... 35 to 600 amu

TABLE 2.—APPROXIMATE RETENTIONTIME FOR COMPOUNDS

Compound

Approximateretention

time (min-utes)

Toluene ..................................... 5.6Octane, n¥C8 .......................... 7.2Ethylbenzene ............................ 10.31,2,4-Trimethylbenzene ............ 16.0Decane, ¥C10 .......................... 16.1TCB (Internal Standard) ........... 21.3Dodecane, ¥C12 ...................... 22.91-Methylnaphthalene ................ 26.71-Tetradecene .......................... 28.4Tetradecane, ¥C14 .................. 28.71,3-Dimethylnaphthalene .......... 29.7

10.2 Internal standard calibrationprocedure—1,3,5-trichlorobenzene (TCB) hasbeen shown to be free of interferences fromdiesel and crude oils and is a suitableinternal standard.

10.3 The system performance test mixstandards prepared in Section 7.2.4 of thisappendix shall be used to establish retentiontimes and establish qualitative detectionlimits.

10.3.1 Spike a 500-mL aliquot of the 1.25mg/mL SPTM standard with 500 µL of theTCB internal standard solution.

10.3.2 Inject 1.0 µL of this spiked SPTMstandard onto the GC/MS in order todemonstrate proper retention times. For theGC/MS used in the development of thismethod, the ten compounds in the mixturehad typical retention times shown in Table2 of this appendix. Extracted ion scans for m/z 91 and 105 showed a maximum abundanceof 400,000.

10.3.3 Spike a 500-mL aliquot of the0.125 mg/mL SPTM standard with 500 µL ofthe TCB internal standard solution.

10.3.4 Inject 1.0 µL of this spiked SPTMstandard onto the GC/MS to monitordetectable levels. For the GC/MS used in the

development of this test, all ten compoundsshowed a minimum peak height of threetimes signal to noise. Extracted ion scans form/z 91 and 105 showed a maximumabundance of 40,000.

10.4 GC/MS crude oil/drilling fluidcalibration—There are two methods ofquantification: Total Area Integration (C8–C13) and EIP Area Integration using m/z’s 91and 105. The Total Area Integration methodshould be used as the primary technique forquantifying crude oil in NAFs. The EIP AreaIntegration method should be used as aconfirmatory technique for NAFs. However,the EIP Area Integration method shall beused as the primary method for quantifyingoil in enhanced mineral oil (EMO) baseddrilling fluid. Inject 1.0 µL of each of the fourcrude oil/drilling fluid calibration standardsprepared in Section 7.2.5 of this appendixinto the GC/MS. The internal standardshould elute approximately 21–22 minutesafter injection. For the GC/MS used in thedevelopment of this method, the internalstandard peak was (35 to 40)% of full scaleat an abundance of about 3.5e+07.

10.4.1 Total Area Integration Method—For each of the four calibration standardsobtain the following: Using a straightbaseline integration technique, obtain thetotal ion chromatogram (TIC) area from C8 toC13. Obtain the TIC area of the internalstandard (TCB). Subtract the TCB area fromthe C8–C13 area to obtain the true C8–C13 area.Using the C8–C13 and TCB areas, and knowninternal standard concentration, generate alinear regression calibration using theinternal standard method. The r2 value forthe linear regression curve shall be greaterthan or equal to 0.998. Some synthetic fluidsmight have peaks that elute in the windowand would interfere with the analysis. In thiscase the integration window can be shifted toother areas of scan where there are nointerfering peaks from the synthetic basefluid.

10.4.2 EIP Area Integration—For each ofthe four calibration standards generateExtracted Ion Profiles (EIPs) for m/z 91 and105. Using straight baseline integrationtechniques, obtain the following EIP areas:

10.4.2.1 For m/z 91 integrate the areaunder the curve from approximately 9minutes to 21–22 minutes, just prior to butnot including the internal standard.

10.4.2.2 For m/z 105 integrate the areaunder the curve from approximately 10.5minutes to 26.5 minutes.

10.4.2.3 Obtain the internal standard areafrom the TCB in each of the four calibrationstandards, using m/z 180.

10.4.2.4 Using the EIP areas for TCB, m/z 91 and m/z105, and the knownconcentration of internal standard, generatelinear regression calibration curves for thetarget ions 91 and 105 using the internalstandard method. The r2 value for each of theEIP linear regression curves shall be greaterthan or equal to 0.998.

10.4.2.5 Some base fluids might producea background level that would show up onthe extracted ion profiles, but there shouldnot be any real peaks (signal to noise ratioof 1:3) from the clean base fluids.

11.0 Procedure

11.1 Sample Preparation—11.1.1 Mix the authentic field sample

(drilling fluid) well. Transfer (weigh) a 30-galiquot of the sample to a labeled centrifugetube.

11.1.2 Centrifuge the aliquot for aminimum of 15 min at approximately 15,000rpm, in order to obtain a solids freesupernate.

11.1.3 Weigh 0.5 g of the supernatedirectly into a tared and appropriatelylabeled GC straight vial.

11.1.4 Spike the 0.5-g supernate with 500µL of the 0.01g/mL 1,3,5-trichlorobenzeneinternal standard solution (see Section 7.2.3of this appendix), cap with a Teflon linedcrimp cap, and vortex for ca. 10 sec.

11.1.5 The sample is ready for GC/MSanalysis.

11.2 Gas Chromatography.Table 1 of this appendix summarizes the

recommended operating conditions for theGC/MS. Retention times for the n-alkanesobtained under these conditions are given inTable 2 of this appendix. Other columns,chromatographic conditions, or detectorsmay be used if initial precision and accuracyrequirements (Section 9.2 of this appendix)are met. The system shall be calibratedaccording to the procedures outlined inSection 10 of this appendix, and verifiedevery 12 hours according to Section 11.6 ofthis appendix.

11.2.1 Samples shall be prepared(extracted) in a batch of no more than 20samples. The batch shall consist of 20authentic samples, 1 blank (Section 9.3 ofthis appendix), 1 matrix spike sample (9.4),and 1 duplicate field sample (9.5), and aprepared sample of the corresponding cleanNAF used in the drilling process.

11.2.2 An analytical sequence shall beanalyzed on the GC/MS where the 3 SPTMstandards (Section 7.2.4 of this appendix)containing internal standard are analyzedfirst, followed by analysis of the four GC/MScrude oil/drilling fluid calibration standards(Section 7.2.5 of this appendix), analysis ofthe blank, matrix spike sample, the duplicatesample, the clean NAF sample, followed bythe authentic samples.

11.2.3 Samples requiring dilution due toexcessive signal shall be diluted usingmethylene chloride.

11.2.4 Inject 1.0 µL of the test sample orstandard into the GC, using the conditions inTable 1 of this appendix.

11.2.5 Begin data collection and thetemperature program at the time of injection.

11.2.6 Obtain a TIC and EIP fingerprintscans of the sample (Table 3 of thisappendix).

11.2.7 If the area of the C8 to C13 peaksexceeds the calibration range of the system,dilute a fresh aliquot of the test sampleweighing 0.50-g and re-analyze.

11.2.8 Determine the C8 to C13 TIC area,the TCB internal standard area, and the areasfor the m/z 91 and 105 EIPs. These shall beused in the calculation of oil concentrationin the samples (see Section 12 of thisappendix).



TABLE 3.—RECOMMENDED ION MASS NUMBERS

Selected ion mass numbers Corresponding aromatic compounds Typical rententiontime (minutes)

91 ............................................................................................. Methylbenzene ........................................................................ 6.0Ethylbenzene ........................................................................... 10.31,4-Dimethylbenzene ............................................................... 10.91,3-Dimethylbenzene ............................................................... 10.91,2-Dimethylbenzene ............................................................... 11.9

105 ........................................................................................... 1,3,5-Trimethylbenzene ........................................................... 15.11,2,4-Trimethylbenzene ........................................................... 16.01,2,3-Trimethylbenzene ........................................................... 17.4

156 ........................................................................................... 2,6-Dimethylnaphthalene ......................................................... 28.91,2-Dimethylnaphthalene ......................................................... 29.41,3-Dimethylnaphthalene ......................................................... 29.7

11.2.9 Observe the presence of peaks inthe EIPs that would confirm the presence ofany target aromatic compounds. Using theEIP areas and EIP linear regressioncalibrations compare the abundance of thearomatic peaks, and if appropriate, determineapproximate crude oil contamination in thesample for each of the target ions.

11.3 Qualitative Identification—SeeSection 17 of this appendix for schematicflowchart.

11.3.1 Qualitative identification shall beaccomplished by comparison of the TIC andEIP area data from an authentic sample to theTIC and EIP area data from the calibrationstandards (Section 12.4 of this appendix).Crude oil shall be identified by the presenceof C10 to C13 n-alkanes and correspondingtarget aromatics.

11.3.2 Using the calibration data,establish the identity of the C8 to C13 peaksin the chromatogram of the sample. Using thecalibration data, establish the identity of anytarget aromatics present on the extracted ionscans.

11.3.3 Crude oil is not present in adetectable amount in the sample if there areno target aromatics seen on the extracted ionscans. The experience of the analyst shallweigh heavily in the determination of thepresence of peaks at a signal-to-noise ratio of3 or greater.

11.3.4 If the chromatogram shows n-alkanes from C8 to C13 and target aromaticsto be present, contamination by crude oil ordiesel shall be suspected and quantitativeanalysis shall be determined. If there are non-alkanes present that are not seen on theblank, and no target aromatics are seen, thesample can be considered to be free ofcontamination.

11.4 Quantitative Identification—11.4.1 Determine the area of the peaks

from C8 to C13 as outlined in the calibrationsection (10.4.1 of this appendix). If the areaof the peaks for the sample is greater thanthat for the clean NAF (base fluid) use thecrude oil/drilling fluid calibration TIC linearregression curve to determine approximatecrude oil contamination.

11.4.2 Using the EIPs outlined in Section10.4.2 of this appendix, determine thepresence of any target aromatics. Using theintegration techniques outlined in Section10.4.2 of this appendix, obtain the EIP areasfor m/z 91 and 105. Use the crude oil/drillingfluid calibration EIP linear regression curves

to determine approximate crude oilcontamination.

11.5 Complex Samples—11.5.1 The most common interferences in

the determination of crude oil can be frommineral oil, diesel oil, and proprietaryadditives in drilling fluids.

11.5.2 Mineral oil can typically beidentified by its lower target aromaticcontent, and narrow range of strong peaks.

11.5.3 Diesel oil can typically beidentified by low amounts of n-alkanes fromC7 to C9, and the absence of n-alkanes greaterthan C25.

11.5.4 Crude oils can usually bedistinguished by the presence of higharomatics, increased intensities of C8 to C13

peaks, and/ or the presence of higherhydrocarbons of C25 and greater (which maybe difficult to see in some synthetic fluids atlow contamination levels).

11.5.4.1 Oil condensates from gas wellsare low in molecular weight and willnormally produce strong chromatographicpeaks in the C8–C13 range. If a sample of thegas condensate crude oil from the formationis available, the oil can be distinguished fromother potential sources of contamination byusing it to prepare a calibration standard.

11.5.4.2 Asphaltene crude oils with APIgravity 20 may not produce chromatographicpeaks strong enough to show contaminationat levels of the calibration. Extracted ionpeaks should be easier to see than increasedintensities for the C8 to C13 peaks. If a sampleof asphaltene crude from the formation isavailable, a calibration standard shall beprepared.

11.6 System and LaboratoryPerformance—

11.6.1 At the beginning of each 8-hourshift during which analyses are performed,GC crude oil/drilling fluid calibration andsystem performance test mixes shall beverified. For these tests, analysis of themedium-level calibration standard (1-%Reference Oil in IO Lab drilling fluid, and1.25 mg/mL SPTM with internal standard)shall be used to verify all performancecriteria. Adjustments and/or re-calibration(per Section 10 of this appendix) shall beperformed until all performance criteria aremet. Only after all performance criteria aremet may samples and blanks be analyzed.

11.6.2 Inject 1.0 µL of the medium-levelGC/MS crude oil/drilling fluid calibrationstandard into the GC instrument according tothe procedures in Section 11.2 of this

appendix. Verify that the linear regressioncurves for both TIC area and EIP areas arestill valid using this continuing calibrationstandard.

11.6.3 After this analysis is complete,inject 1.0 µL of the 1.25 mg/mL SPTM(containing internal standard) into the GCinstrument and verify the proper retentiontimes are met (see Table 2 of this appendix).

11.6.4 Retention times—Retention time ofthe internal standard. The absolute retentiontime of the TCB internal standard shall bewithin the range 21.0 ± 0.5 minutes. Relativeretention times of the n-alkanes: Theretention times of the n-alkanes relative tothe TCB internal standard shall be similar tothose given in Table 2 of this appendix.

12.0 CalculationsThe concentration of oil in NAFs drilling

fluids shall be computed relative to peakareas between C8 and C13 (using the TotalArea Integration method) or total peak areasfrom extracted ion profiles (using theExtracted Ion Profile Method). In either case,there is a measurable amount of peak area,even in clean drilling fluid samples, due tospurious peaks and electrometer ‘‘noise’’ thatcontributes to the total signal measured usingeither of the quantification methods. In thisprocedure, a correction for this signal isapplied, using the blank or clean samplecorrection technique described in AmericanSociety for Testing Materials (ASTM) MethodD–3328–90, Comparison of Waterborne Oilby Gas Chromatography. In this method, the‘‘oil equivalents’’ measured in a blank sampleby total area gas chromatography aresubtracted from that determined for a fieldsample to arrive at the most accurate measureof oil residue in the authentic sample.

12.1 Total Area Integration Method12.1.1 Using C8 to C13 TIC area, the TCB

area in the clean NAF sample and the TIClinear regression curve, compute the oilequivalent concentration of the C8 to C13

retention time range in the clean NAF.Note: The actual TIC area of the C8 to C13

is equal to the C8 to C13 area minus the areaof the TCB.

12.1.2 Using the correspondinginformation for the authentic sample,compute the oil equivalent concentration ofthe C8 to C13 retention time range in theauthentic sample.

12.1.3 Calculate the concentration (% oil)of oil in the sample by subtracting the oil



equivalent concentration (% oil) found in theclean NAF from the oil equivalentconcentration (% oil) found in the authenticsample.

12.2 EIP Area Integration Method12.2.1 Using either m/z 91 or 105 EIP

areas, the TCB area in the clean NAF sample,and the appropriate EIP linear regressioncurve, compute the oil equivalentconcentration of the in the clean NAF.

12.2.2 Using the correspondinginformation for the authentic sample,compute its oil equivalent concentration.

12.2.3 Calculate the concentration (% oil)of oil in the sample by subtracting the oilequivalent concentration (% oil) found in theclean NAF from the oil equivalentconcentration (% oil) found in the authenticsample.

13.0 Method Performance13.1 Specification in this method are

adopted from EPA Method 1663,Differentiation of Diesel and Crude Oil byGC/FID (Reference 16.5).

13.2 Single laboratory methodperformance using an Internal Olefin (IO)drilling fluid fortified at 0.5% oil using a 35API gravity oil was:Precision and accuracy 94±4%Accuracy interval—86.3% to 102%Relative percent difference in duplicate

analysis—6.2%

14.0 Pollution Prevention14.1 The solvent used in this method

poses little threat to the environment whenrecycled and managed properly.

15.0 Waste Management15.1 It is the laboratory’s responsibility to

comply with all federal, state, and localregulations governing waste management,particularly the hazardous wasteidentification rules and land disposalrestriction, and to protect the air, water, andland by minimizing and controlling allreleases from fume hoods and benchoperations. Compliance with all sewagedischarge permits and regulations is alsorequired.

15.2 All authentic samples (drillingfluids) failing the RPE (fluorescence) test(indicated by the presence of fluorescence)shall be retained and classified ascontaminated samples. Treatment andultimate fate of these samples is not outlinedin this SOP.

15.3 For further information on wastemanagement, consult ‘‘The WasteManagement Manual for LaboratoryPersonnel’’, and ‘‘Less is Better: LaboratoryChemical Management for Waste Reduction’’,both available from the American ChemicalSociety’s Department of GovernmentRelations and Science Policy, 1155 16thStreet NW, Washington, DC 20036.

16.0 References16.1 Carcinogens—‘‘Working With

Carcinogens.’’ Department of Health,Education, and Welfare, Public HealthService, Centers for Disease Control(available through National TechnicalInformation Systems, 5285 Port Royal Road,Springfield, VA 22161, document no. PB–277256): August 1977.

16.2 ‘‘OSHA Safety and HealthStandards, General Industry [29 CFR 1910],Revised.’’ Occupational Safety and HealthAdministration, OSHA 2206. Washington,DC: January 1976.

16.3 ‘‘Handbook of Analytical QualityControl in Water and WastewaterLaboratories.’’ USEPA, EMSSL–CI, EPA–600/4–79–019. Cincinnati, OH: March 1979.

16.4 ‘‘Method 1663, Differentiation ofDiesel and Crude Oil by GC/FID, Methods forthe Determination of Diesel, Mineral, andCrude Oils in Offshore Oil and Gas IndustryDischarges, EPA 821–R–92–008, Office ofWater Engineering and Analysis Division,Washington, DC: December 1992.

Appendix 6 to Subpart A of Part 435—Reverse Phase Extraction (RPE) Method forDetection of Oil Contamination in Non-Aqueous Drilling Fluids (NAF)

1.0 Scope and Application1.1 This method is used for

determination of crude or formation oil, orother petroleum oil contamination, in non-aqueous drilling fluids (NAFs).

1.2 This method is intended as a positive/negative test to determine a presence of crudeoil in NAF prior to discharging drill cuttingsfrom offshore production platforms.

1.3 This method is for use in theEnvironmental Protection Agency’s (EPA’s)survey and monitoring programs under theClean Water Act, including monitoring ofcompliance with the Gulf of Mexico NPDESGeneral Permit for monitoring of oilcontamination in drilling fluids.

1.4 This method has been designed toshow positive contamination for 5% ofrepresentative crude oils at a concentration of0.1% in drilling fluid (vol/vol), 50% ofrepresentative crude oils at a concentration of0.5%, and 95% of representative crude oilsat a concentration of 1%.

1.5 Any modification of this method,beyond those expressly permitted, shall beconsidered a major modification subject toapplication and approval of alternate testprocedures under 40 CFR Parts 136.4 and136.5.

1.6 Each laboratory that uses this methodmust demonstrate the ability to generateacceptable results using the procedure inSection 9.2 of this appendix.

2.0 Summary of Method2.1 An aliquot of drilling fluid is

extracted using isopropyl alcohol.2.2 The mixture is allowed to settle and

then filtered to separate out residual solids.2.3 An aliquot of the filtered extract is

charged onto a reverse phase extraction (RPE)cartridge.

2.4 The cartridge is eluted with isopropylalcohol.

2.5 Crude oil contaminates are retainedon the cartridge and their presence (orabsence) is detected based on observedfluorescence using a black light.

3.0 Definitions3.1 A NAF is one in which the

continuous phase is a water immiscible fluidsuch as an oleaginous material (e.g., mineraloil, enhance mineral oil, paraffinic oil, orsynthetic material such as olefins andvegetable esters).

4.0 Interferences4.1 Solvents, reagents, glassware, and

other sample-processing hardware may yieldartifacts that affect results. Specific selectionof reagents and purification of solvents maybe required.

4.2 All materials used in the analysisshall be demonstrated to be free frominterferences under the conditions of analysisby running laboratory reagent blanks asdescribed in Section 9.5 of this appendix.

5.0 Safety5.1 The toxicity or carcinogenicity of

each reagent used in this method has notbeen precisely determined; however, eachchemical shall be treated as a potential healthhazard. Exposure to these chemicals shouldbe reduced to the lowest possible level.Material Safety Data Sheets (MSDSs) shall beavailable for all reagents.

5.2 Isopropyl alcohol is flammable andshould be used in a well-ventilated area.

5.3 Unknown samples may contain highconcentration of volatile toxic compounds.Sample containers should be opened in ahood and handled with gloves to preventexposure. In addition, all sample preparationshould be conducted in a well-ventilated areato limit the potential exposure to harmfulcontaminants. Drilling fluid samples shouldbe handled with the same precautions usedin the drilling fluid handling areas of thedrilling rig.

5.4 This method does not address allsafety issues associated with its use. Thelaboratory is responsible for maintaining asafe work environment and a currentawareness file of OSHA regulations regardingthe safe handling of the chemicals specifiedin this method. A reference file of materialsafety data sheets (MSDSs) shall be availableto all personnel involved in these analyses.Additional information on laboratory safetycan be found in References 16.1–16.2.

6.0 Equipment and Supplies

Note: Brand names, suppliers, and partnumbers are for illustrative purposes only.No endorsement is implied. Equivalentperformance may be achieved usingapparatus and materials other than thosespecified here, but demonstration ofequivalent performance that meets therequirements of this method is theresponsibility of the laboratory.

6.1 Sampling equipment.6.1.1 Sample collection bottles/jars—

New, pre-cleaned bottles/jars, lot-certified tobe free of artifacts. Glass preferable, plasticacceptable, wide mouth approximately 1–L,with Teflon-lined screw cap.

6.2 Equipment for glassware cleaning.6.2.1 Laboratory sink.6.2.2 Oven—Capable of maintaining a

temperature within ±5°C in the range of 100–250 °C.

6.3 Equipment for sample extraction.6.3.1 Vials—Glass, 25 mL and 4 mL, with

Teflon-lined screw caps, baked at 200–250 °Cfor 1–h minimum prior to use.

6.3.2 Gas-tight syringes—Glass, varioussizes, 0.5 mL to 2.5 mL (if spiking of drillingfluids with oils is to occur).

6.3.3 Auto pipetters—various sizes, 0.1mL, 0.5 mL, 1 to 5 mL delivery, and 10 mL



delivery, with appropriate size disposablepipette tips, calibrated to within ±0.5%.

6.3.4 Glass stirring rod.6.3.5 Vortex mixer.6.3.6 Disposable syringes—Plastic, 5 mL.6.3.7 Teflon syringe filter, 25-mm,

0.45µm pore size—Acrodisc CR Teflon (orequivalent).

6.3.8 Reverse Phase Extraction C18

Cartridge—Waters Sep-PakPlus, C18

Cartridge, 360 mg of sorbent (or equivalent).6.3.9 SPE vacuum manifold—Supelco

Brand, 12 unit (or equivalent). Used assupport for cartridge/syringe assembly only.Vacuum apparatus not required.

6.4 Equipment for fluorescence detection.6.4.1 Black light—UV Lamp, Model UVG

11, Mineral Light Lamp, Shortwave 254 nm,or Longwave 365 nm, 15 volts, 60 Hz, 0.16amps (or equivalent).

6.4.2 Black box—cartridge viewing area.A commercially available ultraviolet viewingcabinet with viewing lamp, or alternatively,a cardboard box or equivalent, approximately14″×7.5″×7.5″ in size and painted flat blackinside. Lamp positioned in fitted and sealedslot in center on top of box. Samplecartridges sit in a tray, ca. 6″ from lamp.Cardboard flaps cut on top panel and side offront panel for sample viewing and samplecartridge introduction, respectively.

6.4.3 Viewing platform for cartridges.Simple support (hand made vial tray—blackin color) for cartridges so that they do notmove during the fluorescence testing.

7.0 Reagents and Standards7.1 Isopropyl alcohol—99% purity.7.2 NAF—Appropriate NAF as sent from

the supplier (has not been circulateddownhole). Use the clean NAF correspondingto the NAF being used in the current drillingoperation.

7.3 Standard crude oil—NIST SRM 1582petroleum crude oil.

8.0 Sample Collection, Preservation, andStorage

8.1 Collect approximately one liter ofrepresentative sample (NAF, which has beencirculated downhole) in a glass bottle or jar.Cover with a Teflon lined cap. To allow fora potential need to re-analyze and/or re-process the sample, it is recommended thata second sample aliquot be collected.

8.2 Label the sample appropriately.8.3 All samples must be refrigerated at 0–

4 °C from the time of collection untilextraction (40 CFR Part 136, Table II).

8.4 All samples must be analyzed within28 days of the date and time of collection (40CFR Part 136, Table II).

9.0 Quality Control9.1 Each laboratory that uses this method

is required to operate a formal qualityassurance program (Reference 16.3). Theminimum requirements of this programconsist of an initial demonstration oflaboratory capability, and ongoing analysesof blanks and spiked duplicates to assessaccuracy and precision and to demonstratecontinued performance. Each field sample isanalyzed in duplicate to demonstraterepresentativeness.

9.1.1 The analyst shall make an initialdemonstration of the ability to generate

acceptable accuracy and precision with thismethod. This ability is established asdescribed in Section 9.2 of this appendix.

9.1.2 Preparation and analysis of a set ofspiked duplicate samples to documentaccuracy and precision. The procedure forthe preparation and analysis of these samplesis described in Section 9.4 of this appendix.

9.1.3 Analyses of laboratory reagentblanks are required to demonstrate freedomfrom contamination. The procedure andcriteria for preparation and analysis of areagent blank are described in Section 9.5 ofthis appendix.

9.1.4 The laboratory shall maintainrecords to define the quality of the data thatis generated.

9.1.5 Accompanying QC for thedetermination of oil in NAF is required peranalytical batch. An analytical batch is a setof samples extracted at the same time, to amaximum of 10 samples. Each analyticalbatch of 10 or fewer samples must beaccompanied by a laboratory reagent blank(Section 9.5 of this appendix), correspondingNAF reference blanks (Section 9.6 of thisappendix), a set of spiked duplicate samplesblank (Section 9.4 of this appendix), andduplicate analysis of each field sample. Ifgreater than 10 samples are to be extractedat one time, the samples must be separatedinto analytical batches of 10 or fewersamples.

9.2 Initial demonstration of laboratorycapability. To demonstrate the capability toperform the test, the analyst shall analyzetwo representative unused drilling fluids(e.g., internal olefin-based drilling fluid,vegetable ester-based drilling fluid), eachprepared separately containing 0.1%, 1%,and 2% or a representative oil. Each drillingfluid/concentration combination shall beanalyzed 10 times, and successfuldemonstration will yield the followingaverage results for the data set:0.1% oil—Detected in <20% of samples1% oil—Detected in >75% of samples2% oil—Detected in <90% of samples

9.3 Sample duplicates.9.3.1 The laboratory shall prepare and

analyze (Section 11.2 and 11.4 of thisappendix) each authentic sample induplicate, from a given sampling site or, if forcompliance monitoring, from a givendischarge.

9.3.2 The duplicate samples must becompared versus the prepared correspondingNAF blank.

9.3.3 Prepare and analyze the duplicatesamples according to procedures outlined inSection 11 of this appendix.

9.3.4 The results of the duplicate analysesare acceptable if each of the results give thesame response (fluorescence or nofluorescence). If the results are different,sample non-homogenicity issues may be aconcern. Prepare the samples again, ensuringa well-mixed sample prior to extraction.Analyze the samples once again.

9.3.5 If different results are obtained forthe duplicate a second time, the analyticalsystem is judged to be out of control and theproblem shall be identified and corrected,and the samples re-analyzed.

9.4 Spiked duplicates—Laboratoryprepared spiked duplicates are analyzed to

demonstrate acceptable accuracy andprecision.

9.4.1 Preparation and analysis of a set ofspiked duplicate samples with each set of nomore than 10 field samples is required todemonstrate method accuracy and precisionand to monitor matrix interferences(interferences caused by the sample matrix).A field NAF sample expected to contain lessthan 0.5% crude oil (and documented to notfluoresce as part of the sample batchanalysis) shall be spiked with 1% (byvolume) of suitable reference crude oil andanalyzed as field samples, as described inSection 11 of this appendix. If no low-leveldrilling fluid is available, then the unusedNAF can be used as the drilling fluid sample.

9.5 Laboratory reagent blanks—Laboratory reagent blanks are analyzed todemonstrate freedom from contamination.

9.5.1 A reagent blank is prepared bypassing 4 mL of the isopropyl alcoholthrough a Teflon syringe filter and collectingthe filtrate in a 4-mL glass vial. A Sep Pak

C18 cartridge is then preconditioned with 3mL of isopropyl alcohol. A 0.5-mL aliquot ofthe filtered isopropyl alcohol is added to thesyringe barrel along with 3.0 mL of isopropylalcohol. The solvent is passed through thepreconditioned Sep Pak cartridge. Anadditional 2-mL of isopropyl alcohol iseluted through the cartridge. The cartridge isnow considered the ‘‘reagent blank’’ cartridgeand is ready for viewing (analysis). Check thereagent blank cartridge under the black lightfor fluorescence. If the isopropyl alcohol andfilter are clean, no fluorescence will beobserved.

9.5.2 If fluorescence is detected in thereagent blank cartridge, analysis of thesamples is halted until the source ofcontamination is eliminated and a preparedreagent blank shows no fluorescence under ablack light. All samples shall be associatedwith an uncontaminated method blank beforethe results may be reported for regulatorycompliance purposes.

9.6 NAF reference blanks—NAF referenceblanks are prepared from the NAFs sent fromthe supplier (NAF that has not beencirculated downhole) and used as thereference when viewing the fluorescence ofthe test samples.

9.6.1 A NAF reference blank is preparedidentically to the authentic samples. Place a0.1 mL aliquot of the ‘‘clean’’ NAF into a 25-mL glass vial. Add 10 mL of isopropylalcohol to the vial. Cap the vial. Vortex thevial for approximately 10 sec. Allow thesolids to settle for approximately 15 minutes.Using a 5-mL syringe, draw up 4 mL of theextract and filter it through a PTFE syringefilter, collecting the filtrate in a 4-mL glassvial. Precondition a Sep Pak C18 cartridgewith 3 mL of isopropyl alcohol. Add a 0.5-mL aliquot of the filtered extract to thesyringe barrel along with 3.0 mL of isopropylalcohol. Pass the extract and solvent throughthe preconditioned Sep Pak cartridge. Passan additional 2-mL of isopropyl alcoholthrough the cartridge. The cartridge is nowconsidered the NAF blank cartridge and isready for viewing (analysis). This cartridge isused as the reference cartridge fordetermining the absence or presence offluorescence in all authentic drilling fluid



samples that originate from the same NAF.That is, the specific NAF reference blankcartridge is put under the black light alongwith a prepared cartridge of an authenticsample originating from the same NAFmaterial. The fluorescence or absence offluorescence in the authentic samplecartridge is determined relative to the NAFreference cartridge.

9.6.2 Positive control solution, equivalentto 1% crude oil contaminated mud extract,is prepared by dissolving 87 mg of standardcrude oil into 10.00 mL of methylenechloride. Then mix 40 µL of this solution into10.00 mL of IPA. Transfer 0.5 mL of thissolution into a preconditioned C18 cartridge,followed by 2 ml of IPA.

10.0 Calibration and Standardization10.1 Calibration and standardization

methods are not employed for this procedure.

11.0 ProcedureThis method is a screening-level test.

Precise and accurate results can be obtainedonly by strict adherence to all details.

11.1 Preparation of the analytical batch.11.1.1 Bring the analytical batch of

samples to room temperature.11.1.2 Using a large glass stirring rod, mix

the authentic sample thoroughly.11.1.3 Using a large glass stirring rod, mix

the clean NAF (sent from the supplier)thoroughly.

11.2 Extraction.11.2.1 Using an automatic positive

displacement pipetter and a disposablepipette tip transfer 0.1-mL of the authenticsample into a 25-mL vial.

11.2.2 Using an automatic pipetter and adisposable pipette tip dispense a 10-mLaliquot of solvent grade isopropyl alcohol(IPA) into the 25 mL vial.

11.2.3 Cap the vial and vortex the vial forca. 10–15 seconds.

11.2.4 Let the sample extract stand forapproximately 5 minutes, allowing the solidsto separate.

11.2.5 Using a 5-mL disposable plasticsyringe remove 4 mL of the extract from the25-mL vial.

11.2.6 Filter 4 mL of extract through aTeflon syringe filter (25-mm diameter, 0.45µm pore size), collecting the filtrate in alabeled 4-mL vial.

11.2.7 Dispose of the PFTE syringe filter.11.2.8 Using a black permanent marker,

label a Sep Pak C18 cartridge with thesample identification.

11.2.9 Place the labeled Sep Pak C18

cartridge onto the head of a SPE vacuummanifold.

11.2.10 Using a 5-mL disposable plasticsyringe, draw up exactly 3-mL (air free) ofisopropyl alcohol.

11.2.11 Attach the syringe tip to the topof the C18 cartridge.

11.2.12 Condition the C18 cartridge withthe 3-mL of isopropyl alcohol by depressingthe plunger slowly.

Note: Depress the plunger just to the pointwhen no liquid remains in the syringe barrel.Do not force air through the cartridge. Collectthe eluate in a waste vial.

11.2.13 Remove the syringe temporarilyfrom the top of the cartridge, then remove the

plunger, and finally reattach the syringebarrel to the top of the C18 cartridge.

11.2.14 Using automatic pipetters anddisposable pipette tips, transfer 0.5 mL of thefiltered extract into the syringe barrel,followed by a 3.0-mL transfer of isopropylalcohol to the syringe barrel.

11.2.15 Insert the plunger and slowlydepress it to pass only the extract and solventthrough the preconditioned C18 cartridge.

Note: Depress the plunger just to the pointwhen no liquid remains in the syringe barrel.Do not force air through the cartridge. Collectthe eluate in a waste vial.

11.2.16 Remove the syringe temporarilyfrom the top of the cartridge, then remove theplunger, and finally reattach the syringebarrel to the top of the C18 cartridge.

11.2.17 Using an automatic pipetter anddisposable pipette tip, transfer 2.0 mL ofisopropyl alcohol to the syringe barrel.

11.2.18 Insert the plunger and slowlydepress it to pass the solvent through the C18

cartridge.Note: Depress the plunger just to the point

when no liquid remains in the syringe barrel.Do not force air through the cartridge. Collectthe eluate in a waste vial.

11.2.19 Remove the syringe and labeledC18 cartridge from the top of the SPE vacuummanifold.

11.2.20 Prepare a reagent blank accordingto the procedures outlined in Section 9.5 ofthis appendix.

11.2.21 Prepare the necessary NAFreference blanks for each type of NAFencountered in the field samples according tothe procedures outlined in Section 9.6 of thisappendix.

11.2.22 Prepare the positive control (1%crude oil equivalent) according to Section9.6.2 of this appendix.

11.3 Reagent blank fluorescence testing.11.3.1 Place the reagent blank cartridge in

a black box, under a black light.11.3.2 Determine the presence or absence

of fluorescence for the reagent blankcartridge. If fluorescence is detected in theblank, analysis of the samples is halted untilthe source of contamination is eliminatedand a prepared reagent blank shows nofluorescence under a black light. All samplesmust be associated with an uncontaminatedmethod blank before the results may bereported for regulatory compliance purposes.

11.4 Sample fluorescence testing.11.4.1 Place the respective NAF reference

blank (Section 9.6 of this appendix) onto thetray inside the black box.

11.4.2 Place the authentic field samplecartridge (derived from the same NAF as theNAF reference blank) onto the tray, adjacentand to the right of the NAF reference blank.

11.4.3 Turn on the black light.11.4.4 Compare the fluorescence of the

sample cartridge with that of the negativecontrol cartridge (NAF blank, Section 9.6.1 ofthis appendix) and positive control cartridge(1% crude oil equivalent, Section 9.6.2 ofthis appendix).

11.4.5 If the fluorescence of the samplecartridge is equal to or brighter than thepositive control cartridge (1% crude oilequivalent, Section 9.6.2 of this appendix),the sample is considered contaminated.Otherwise, the sample is clean.

12.0 Data Analysis and CalculationsSpecific data analysis techniques and

calculations are not performed in this SOP.

13.0 Method PerformanceThis method was validated through a

single laboratory study, conducted withrigorous statistical experimental design andinterpretation (Reference 16.4).

14.0 Pollution Prevention14.1 The solvent used in this method

poses little threat to the environment whenrecycled and managed properly.

15.0 Waste Management15.1 It is the laboratory’s responsibility to

comply with all Federal, State, and localregulations governing waste management,particularly the hazardous wasteidentification rules and land disposalrestriction, and to protect the air, water, andland by minimizing and controlling allreleases from bench operations. Compliancewith all sewage discharge permits andregulations is also required.

15.2 All authentic samples (drillingfluids) failing the fluorescence test (indicatedby the presence of fluorescence) shall beretained and classified as contaminatedsamples. Treatment and ultimate fate of thesesamples is not outlined in this SOP.

15.3 For further information on wastemanagement, consult ‘‘The WasteManagement Manual for LaboratoryPersonnel,’’ and ‘‘Less is Better: LaboratoryChemical Management for Waste Reduction,’’both available from the American ChemicalSociety’s Department of GovernmentRelations and Science Policy, 1155 16thStreet, NW, Washington, DC 20036.

16.0 References16.1 ‘‘Carcinogen—Working with

Carcinogens,’’ Department of Health,Education, and Welfare, Public HealthService, Center for Disease Control, NationalInstitute for Occupational Safety and Health,Publication No. 77–206, August 1977.

16.2 ‘‘OSHA Safety and HealthStandards, General Industry,’’ (29 CFR 1910),Occupational Safety and HealthAdministration, OSHA 2206 (Revised,January 1976).

16.3 ‘‘Handbook of Analytical QualityControl in Water and WastewaterLaboratories,’’ USEPA, EMSL-Ci, Cincinnati,OH 45268, EPA–600/4–79–019, March 1979.

16.4 Report of the Laboratory Evaluationof Static Sheen Test Replacements—ReversePhase Extraction (RPE) Method for DetectingOil Contamination in Synthetic Based Mud(SBM). October 1998. Available from API,1220 L Street, NW, Washington, DC 20005–4070, 202–682–8000.

Appendix 7 to Subpart A of Part 435—APIRecommended Practice 13B–2

1. Description

a. This procedure is specifically intendedto measure the amount of non-aqueousdrilling fluid (NAF) base fluid from cuttingsgenerated during a drilling operation. Thisprocedure is a retort test which measures alloily material (NAF base fluid) and waterreleased from a cuttings sample when heated



in a calibrated and properly operating‘‘Retort’’ instrument.

b. In this retort test a known mass ofcuttings is heated in the retort chamber tovaporize the liquids associated with thesample. The NAF base fluid and water vaporsare then condensed, collected, and measuredin a precision graduated receiver.

Note: Obtaining a representative samplerequires special attention to the details ofsample handling (e.g., location, method,frequency). See Addendum A and B forminimum requirements for collectingrepresentative samples. Additional samplingprocedures in a given area may be specifiedby the NPDES permit controlling authority.

2. Equipmenta. Retort instrument—The recommended

retort instrument has a 50-cm3 volume withan external heating jacket.

Retort Specifications:1. Retort assembly—retort body, cup and

lid.(a) Material: 303 stainless steel or

equivalent.(b) Volume: Retort cup with lid.Cup Volume: 50-cm3.Precision: ±0.25-cm3.2. Condenser—capable of cooling the oil

and water vapors below their liquificationtemperature.

3. Heating jacket—nominal 350 watts.4. Temperature control—capable of

limiting temperature of retort to at least 930°F (500 °C) and enough to boil off all NAFs.

b. Liquid receiver (10-cm3, 20-cm3)—the10-cm3 and 20-cm3 receivers are speciallydesigned cylindrical glassware with roundedbottom to facilitate cleaning and funnel-shaped top to catch falling drops. Forcompliance monitoring under the NPDESprogram, the analyst shall use the 10-cm3

liquid receiver with 0.1 ml graduations toachieve greater accuracy.

1. Receiver specifications:Total volume: 10-cm3, 20-cm3.Precision (0 to 100%): ±0.05 cm3, ±0.05

cm3.Outside diameter: 10-mm, 13-mm.Wall thickness: 1.5±0.1mm, 1.2±0.1mm.Frequency of graduation marks (0 to

100%): 0.10-cm3, 0.10-cm3.Calibration: To contain ‘‘TC’’ @ 20°C.Scale: cm3, cm3

2. Material—Pyrex or equivalent glass.c. Toploading balance—capable of

weighing 2000 g and precision of at least 0.1g. Unless motion is a problem, the analystshall use an electronic balance. Wheremotion is a problem, the analyst may use atriple beam balance.

d. Fine steel wool (No. 000)—for packingretort body.

e. Thread sealant lubricant: hightemperature lubricant, e.g. Never-Seez orequivalent.

f. Pipe cleaners—to clean condenser andretort stem.

g. Brush—to clean receivers.h. Retort spatula—to clean retort cup.i. Corkscrew—to remove spent steel wool.

3. Procedure

a. Clean and dry the retort assembly andcondenser.

b. Pack the retort body with steel wool.c. Apply lubricant/sealant to threads of

retort cup and retort stem.d. Weigh and record the total mass of the

retort cup, lid, and retort body with steelwool. This is mass (A), grams.

e. Collect a representative cuttings sample(see Note in Section 1 of this appendix).

f. Partially fill the retort cup with cuttingsand place the lid on the cup.

g. Screw the retort cup (with lid) onto theretort body, weigh and record the total mass.This is mass (B), grams.

h. Attach the condenser. Place the retortassembly into the heating jacket.

i. Weigh and record the mass of the cleanand dry liquid receiver. This is mass (C),grams. Place the receiver below condenseroutlet.

j. Turn on the retort. Allow it to run aminimum of 1 hour.

Note: If solids boil over into receiver, thetest shall be rerun. Pack the retort body witha greater amount of steel wool and repeat thetest.

k. Remove the liquid receiver. Allow it tocool. Record the volume of water recovered.This is (V), cm3.

Note: If an emulsion interface is presentbetween the oil and water phases, heating theinterface may break the emulsion. As asuggestion, remove the retort assembly fromthe heating jacket by grasping the condenser.Carefully heat the receiver along theemulsion band by gently touching thereceiver for short intervals with the hot retortassembly. Avoid boiling the liquids. After theemulsion interface is broken, allow the liquidreceiver to cool. Read the water volume at thelowest point of the meniscus.

l. Weigh and record the mass of thereceiver and its liquid contents (oil pluswater). This is mass (D), grams.

m. Turn off the retort. Remove the retortassembly and condenser from the heatingjacket and allow them to cool. Remove thecondenser.

n. Weigh and record the mass of the cooledretort assembly without the condenser. Thisis mass (E), grams.

o. Clean the retort assembly and condenser.

4. Calculations

a. Calculate the mass of oil (NAF basefluid) from the cuttings as follows:

1. Mass of the wet cuttings sample (Mw)equals the mass of the retort assembly withthe wet cuttings sample (B) minus the massof the empty retort assembly (A).Mw = B¥A [1]

2. Mass of the dry retorted cuttings (MD)equals the mass of the cooled retort assembly(E) minus the mass of the empty retortassembly (A).MD = E¥A [2]

3. Mass of the NAF base fluid (MBF) equalsthe mass of the liquid receiver with itscontents (D) minus the sum of the mass ofthe dry receiver (C) and the mass of the water(V).MBF = D¥(C + V) [3]

Note: Assuming the density of water is 1g/cm3, the volume of water is equivalent tothe mass of the water.

b. Mass balance requirement:The sum of MD, MBF, and V shall be within

5% of the mass of the wet sample.(MD + MBF + V)/Mw = 0.95 to 1.05 [4]

The procedure shall be repeated if thisrequirement is not met.

c. Reporting oil from cuttings:1. Assume that all oil recovered is NAF

base fluid.2. The mass percent NAF base fluid

retained on the cuttings (%BFi) for thesampled discharge ‘‘i’’ is equal to 100 timesthe mass of the NAF base fluid (MBF) dividedby the mass of the wet cuttings sample (Mw).%BFi = (MBF/Mw) × 100 [5]

Operators discharging small volume NAF-cuttings discharges which do not occurduring a NAF-cuttings discharge samplinginterval (i.e., displaced interfaces,accumulated solids in sand traps, pit clean-out solids, or centrifuge discharges whilecutting mud weight) shall either: (a) Measurethe mass percent NAF base fluid retained onthe cuttings (%BFSVD) for each small volumeNAF-cuttings discharges; or (b) use a defaultvalue of 25% NAF base fluid retained on thecuttings.

3. The mass percent NAF base fluidretained on the cuttings is determined for allcuttings wastestreams and includes finesdischarges and any accumulated solidsdischarged [see Section 4.c.6 of this appendixfor procedures on measuring or estimatingthe mass percent NAF base fluid retained onthe cuttings (%BF) for dual gradient drillingseafloor discharges performed to ensureproper operation of subsea pumps].

4. A mass NAF-cuttings discharge fraction(X, unitless) is calculated for all NAF-cuttings, fines, or accumulated solidsdischarges every time a set of retorts isperformed (see Section 4.c.6 of this appendixfor procedures on measuring or estimatingthe mass NAF-cuttings discharge fraction (X)for dual gradient drilling seafloor dischargesperformed to ensure proper operation ofsubsea pumps). The mass NAF-cuttingsdischarge fraction (X) combines the mass ofNAF-cuttings, fines, or accumulated solidsdischarged from a particular discharge overa set period of time with the total mass ofNAF-cuttings, fines, or accumulated solidsdischarged into the ocean during the sameperiod of time (see Addendum A and B ofthis appendix). The mass NAF-cuttingsdischarge fraction (X) for each discharge iscalculated by direct measurement as:Xi = (Fi)/(G) [6]where:Xi = Mass NAF-cuttings discharge fraction for

NAF-cuttings, fines, or accumulatedsolids discharge ‘‘i’’, (unitless)

Fi = Mass of NAF-cuttings discharged fromNAF-cuttings, fines, or accumulatedsolids discharge ‘‘i’’ over a specifiedperiod of time (see Addendum A and Bof this appendix), (kg)

G = Mass of all NAF-cuttings discharges intothe ocean during the same period of timeas used to calculate Fi, (kg)

If an operator has more than one point ofNAF-cuttings discharge, the mass faction (Xi)must be determined by: (a) Directmeasurement (see Equation 6 of this



Appendix); (b) using the following defaultvalues of 0.85 and 0.15 for the cuttings dryer(e.g., horizontal centrifuge, verticalcentrifuge, squeeze press, High-G linearshakers) and fines removal unit (e.g.,decanting centrifuges, mud cleaners),respectively, when the operator is onlydischarging from the cuttings dryer and thefines removal unit; or (c) using directmeasurement of ‘‘Fi’’ (see Equation 6 of thisAppendix) for fines and accumulated solids,using Equation 6A of this Appendix tocalculate ‘‘GEST’’ for use as ‘‘G’’ in Equation6 of this Appendix, and calculating the mass(kg) of NAF-cuttings discharged from thecuttings dryer (Fi) as the difference betweenthe mass of ‘‘GEST’’ calculated in Equation 6Aof this appendix (kg) and the sum of all finesand accumulated solids mass directlymeasured (kg) (see Equation 6 of thisAppendix).GEST = Estimated mass of all NAF-cuttings

discharges into the ocean during thesame period of time as used to calculateFi (see Equation 6 of this Appendix), (kg)[6A]

where:GEST = Hole Volume (bbl) × (396.9 kg/bbl) ×

(1 + Z/100)Z = The base fluid retained on cuttings

limitation or standard (%) which applyto the NAF being discharge (see§§ 435.13. and 435.15).

Hole Volume (bbl) = [Cross-Section Area ofNAF interval (in2)] × Average Rate ofPenetration (feet/hr) × period of time(min) used to calculate Fi (see Equation6 of this Appendix) × (1 hr/60 min) × (1bbl/5.61 ft3) × (1 ft/12 in)2

Cross-Section Area of NAF interval (in2) =(3.14 × [Bit Diameter (in)]2)/4

Bit Diameter (in) = Diameter of drilling bit forthe NAF interval producing drillingcuttings during the same period of timeas used to calculate Fi (see Equation 6 ofthis Appendix)

Average Rate of Penetration (feet/hr) =Arithmetic average of rate of penetrationinto the formation during the sameperiod of time as used to calculate Fi (seeEquation 6 of this Appendix)

Note: Operators with one NAF-cuttingsdischarge may set the mass NAF-cuttingsdischarge fraction (Xi) equal to 1.0.

5. Each NAF-cuttings, fines, oraccumulated solids discharge has anassociated mass percent NAF base fluidretained on cuttings value (%BF) and massNAF-cuttings discharge fraction (X) eachtime a set of retorts is performed. A singletotal mass percent NAF base fluid retainedon cuttings value (%BFT) is calculated everytime a set of retorts is performed. The singletotal mass percent NAF base fluid retainedon cuttings value (%BFT) is calculated as:%BFT,j = Σ(Xi)×(%BFi) [7]where:%BFT,j = Total mass percent NAF base fluid

retained on cuttings value for retort set‘‘j’’ (unitless as percentage, %)

Xi = Mass NAF-cuttings discharge fraction forNAF-cuttings, fines, or accumulatedsolids discharge ‘‘i’’, (unitless)

%BFi = Mass percent NAF base fluid retainedon the cuttings for NAF-cuttings, fines,or accumulated solids discharge ‘‘i’’ ,(unitless as percentage, %)

Note: ΣXi = 1.Operators with one NAF-cuttings discharge

may set %BFT,j equal to %BFi.6. Operators performing dual gradient

drilling operations may require seafloordischarges of large cuttings (>1⁄4″) to ensurethe proper operation of subsea pumps (e.g.,electrical submersible pumps). Operatorsperforming dual gradient drilling operationswhich lead to seafloor discharges of largecuttings for the proper operation of subseapumps shall either: (a) Measure the masspercent NAF base fluid retained on cuttingsvalue (%BF) and mass NAF-cuttingsdischarge fraction (X) for seafloor dischargeseach time a set of retorts is performed; (b) usethe following set of default values,(%BF=14%; X=0.15); or (c) use acombination of (a) and (b) (e.g., use a defaultvalue for %BF and measure X).

Additionally, operators performing dualgradient drilling operations which lead toseafloor discharges of large cuttings for theproper operation of subsea pumps shall alsoperform the following tasks:

(a) Use side scan sonar or shallow seismicto determine the presence of high densitychemosynthetic communities.Chemosynthetic communities areassemblages of tube worms, clams, mussels,and bacterial mats that occur at naturalhydrocarbon seeps or vents, generally inwater depths of 500 meters or deeper.Seafloor discharges of large cuttings for theproper operation of subsea pumps shall notbe permitted within 1000 feet of a highdensity chemosynthetic community.

(b) Seafloor discharges of large cuttings forthe proper operation of subsea pumps shallbe visually monitored and documented by aRemotely Operated Vehicle (ROV) within thetether limit (approximately 300 feet). Thevisual monitoring shall be conducted prior toeach time the discharge point is relocated(cuttings discharge hose) and conductedalong the same direction as the dischargehose position. Near-seabed currents shall beobtained at the time of the visual monitoring.

(c) Seafloor discharges of large cuttings forthe proper operation of subsea pumps shallbe directed within a 150 foot radius of thewellbore.

7. The weighted mass ratio averaged overall NAF well sections (%BFwell) is thecompliance value that is compared with the‘‘maximum weighted mass ratio averagedover all NAF well sections’’ BAT dischargelimitations (see the table in § 435.13 andfootnote 5 of the table in § 435.43) or the‘‘maximum weighted mass ratio averagedover all NAF well sections’’ NSPS dischargelimitations (see the table in § 435.15 andfootnote 5 of the table in § 435.45). Theweighted mass ratio averaged over all NAFwell sections (%BFwell) is calculated as thearithmetic average of all total mass percentNAF base fluid retained on cuttings values(%BFT) and is given by the followingexpression:

%BFwell = [j=1 to j=n Σ (%BFT,j)]/n [8]where:%BFwell = Weighted mass ratio averaged over

all NAF well sections (unitless aspercentage, %)

%BFT,j = Total mass percent NAF base fluidretained on cuttings value for retort set‘‘j’’ (unitless as percentage, %)

n = Total number of retort sets performedover all NAF well sections (unitless)

Small volume NAF-cuttings dischargeswhich do not occur during a NAF-cuttingsdischarge sampling interval (i.e., displacedinterfaces, accumulated solids in sand traps,pit clean-out solids, or centrifuge dischargeswhile cutting mud weight) shall be massaveraged with the arithmetic average of alltotal mass percent NAF base fluid retainedon cuttings values (see Equation 8 of thisAppendix). An additional sampling intervalshall be added to the calculation of theweighted mass ratio averaged over all NAFwell sections (%BFwell). The mass fraction ofthe small volume NAF-cuttings discharges(XSVD) will be determined by dividing themass of the small volume NAF-cuttingsdischarges (FSVD) by the total mass of NAF-cuttings discharges for the well drillingoperation (GWELL + FSVD).XSVD = FSVD / (GWELL + FSVD) [9]where:XSVD = mass fraction of the small volume

NAF-cuttings discharges (unitless)FSVD = mass of the small volume NAF-

cuttings discharges (kg)GWELL = mass of total NAF-cuttings from the

well (kg)The mass of small volume NAF-cuttings

discharges (FSVD) shall be determined bymultiplying the density of the small volumeNAF-cuttings discharges (ρsvd) times thevolume of the small volume NAF-cuttingsdischarges (VSVD).FSVD = ρsvd × VSVD [10]where:FSVD = mass of small volume NAF-cuttings

discharges (kg)ρsvd = density of the small volume NAF-

cuttings discharges (kg/bbl)VSVD = volume of the small volume NAF-

cuttings discharges (bbl)The density of the small volume NAF-

cuttings discharges shall be measured. Thevolume of small volume discharges (VSVD)shall be either: (a) Be measured or (b) usedefault values of 10 bbl of SBF for eachinterface loss and 75 bbl of SBM for pitcleanout per well.

The total mass of NAF-cuttings dischargesfor the well (GWELL) shall be either: (a)Measured; or (b) calculated by multiplying1.0 plus the arithmetic average of all totalmass percent NAF base fluid retained oncuttings values [see Equation 8 of thisAppendix] times the total hole volume(VWELL) for all NAF well sections times adefault value for the density the formation of2.5 g/cm3 (396.9 kg/bbl).



G i n V bblWELL WELL= + = ( )[ ]( )

× ( ) ×∑1 1 396 9 to j = n %BF (kg/bbl) [11]Tj / .

where:GWELL = total mass of NAF-cuttings discharges for the well (kg)[j = 1 to j = n Σ2(%BFTj)]/n = see Equation 8 of this Appendix (unitless as a percentage)VWELL = total hole volume (VWELL) for all NAF well sections (bbl)

The total hole volume of NAF well sections (VWELL) will be calculated as:

V barrelsWELL ( ) = ×∑ Bit diameter (in) change in measured depth (ft) [12]

2

1029For wells where small volume discharges associated with cuttings are made, %BFWELL becomes:

% / %BF X i n X BFWELL SVD SVD SVD= −( ) × = ( )[ ]( ) + ×∑1 1 to j = n %BF [13]Tj

Note: See Addendum A and B to determinethe sampling frequency to determine the totalnumber of retort sets required for all NAFwell sections.

8. The total number of retort sets (n) isincreased by 1 for each sampling interval (seeSection 2.4, Addendum A of this appendix)when all NAF cuttings, fines, or accumulatedsolids for that sampling interval are retainedfor no discharge. A zero discharge intervalshall be at least 500 feet up to a maximumof three per day. This action has the effectof setting the total mass percent NAF basefluid retained on cuttings value (%BFT) atzero for that NAF sampling interval when allNAF cuttings, fines, or accumulated solidsare retained for no discharge.

9. Operators that elect to use the BestManagement Practices (BMPs) for NAF-cuttings shall use the procedures outlined inAddendum B.

Addendum A to Appendix 7 to Subpart A ofPart 435—Sampling of Cuttings DischargeStreams for use with API RecommendedPractice 13B–2

1.0 Sampling Locations

1.1 Each NAF-cuttings waste stream thatdischarges into the ocean shall be sampledand analyzed as detailed in Appendix 7.NAF-cuttings discharges to the ocean mayinclude discharges from primary shakers,secondary shakers, cuttings dryer, finesremoval unit, accumulated solids, and anyother cuttings separation device whose NAF-cuttings waste is discharged to the ocean.NAF-cuttings wastestreams not directlydischarged to the ocean (e.g., NAF-cuttingsgenerated from shake shakers and sent to acuttings dryer for additional processing) donot require sampling and analysis.

1.2 The collected samples shall berepresentative of each NAF-cuttingsdischarge. Operators shall conduct samplingto avoid the serious consequences of error (i.e.,bias or inaccuracy). Operators shall collectNAF-cuttings samples near the point oforigin and before the solids and liquidfractions of the stream have a chance toseparate from one another. For example,operators shall collect shale shaker NAF-cuttings samples at the point where NAF-cuttings are coming off the shale shaker andnot from a holding container downstreamwhere separation of larger particles from theliquid can take place.

1.3 Operators shall provide a simpleschematic diagram of the solids controlsystem and sample locations to the NPDESpermit controlling authority.

2.0 Type of Sample and SamplingFrequency

2.1 Each NAF-cuttings, fines, oraccumulated solids discharge has anassociated mass percent NAF base fluidretained on cuttings value (%BF) and massNAF-cuttings discharge fraction (X) for eachsampling interval (see Section 2.4 of thisaddendum). Operators shall collect a singlediscrete NAF-cuttings sample for each NAF-cuttings waste stream discharged to the oceanduring every sampling interval.

2.2 Operators shall use measured depthin feet from the Kelly bushing when samplesare collected.

2.3 The NAF-cuttings samples collectedfor the mass fraction analysis (see Equation6, Appendix 7 of Subpart A of this part) shallalso be used for the retort analysis (seeEquations 1–5, Appendix 7 of Subpart A ofthis part).

2.4 Operators shall collect and analyze atleast one set of NAF-cuttings samples per daywhile discharging. Operators engaged in fastdrilling (i.e., greater than 500 linear NAF feetadvancement of drill bit per day) shall collectand analyze one set of NAF-cuttings samplesper 500 linear NAF feet of footage drilled.Operators are not required to collect andanalyze more than three sets of NAF-cuttingssamples per day (i.e., three samplingintervals). Operators performing zerodischarge of all NAF-cuttings (i.e., all NAFcuttings, fines, or accumulated solidsretained for no discharge) shall use thefollowing periods to count samplingintervals: (1) One sampling interval per daywhen drilling is less than 500 linear NAF feetadvancement of drill bit per day; and (2) onesampling interval per 500 linear NAF feet offootage drilled with a maximum of threesampling intervals per day.

2.5 The operator shall measure theindividual masses (Fi, kg) and sum total mass(G, kg) (see Equation 6, Appendix 7 ofsubpart A of this part) over a representativeperiod of time (e.g., <10 minutes) duringsteady-state conditions for each samplinginterval (see Section 2.4 of this addendum).The operator shall ensure that all NAF-cuttings are capture for mass analysis duringthe same sampling time period (e.g., <10

minutes) at approximately the same time(i.e., all individual mass samples collectedwithin one hour of each other).

2.6 Operators using Best ManagementPractices (BMPs) to control NAF-cuttingsdischarges shall follow the procedures inAddendum B to Appendix 7 of subpart A of40 CFR 435.

3.0 Sample Size and Handling3.1 The volume of each sample depends

on the volumetric flow rate (cm3/s) of theNAF-cuttings stream and the sampling timeperiod (e.g., <10 minutes). Consequently,different solids control equipment unitsproducing different NAF-cuttings wastestreams at different volumetric flow rates willproduce different size samples for the sameperiod of time. Operators shall useappropriately sized sample containers foreach NAF-cuttings waste stream to ensure noNAF-cuttings are spilled during samplecollection. Operators shall use the same timeperiod (e.g., <10 minutes) to collect NAF-cuttings samples from each NAF-cuttingswaste stream. Each NAF-cuttings sample sizeshall be at least one gallon. Operators shallclearly mark each container to identify eachNAF-cuttings sample.

3.2 Operators shall not decant, heat,wash, or towel the NAF-cuttings to removeNAF base fluid before mass and retortanalysis.

3.3 Operators shall first calculate themass of each NAF-cuttings sample andperform the mass ratio analysis (see Equation6, Appendix 7 of subpart A of this part).Operators with only one NAF-cuttingsdischarge may skip this step (see Section4.c.4, Appendix 7 of subpart A of this part).

3.4 Operators shall homogenize (e.g.,stirring, shaking) each NAF-cuttings sampleprior to placing a sub-sample into the retortcup. The bottom of the NAF-cuttings samplecontainer shall be examined to be sure thatsolids are not sticking to it.

3.5 Operators shall then calculate theNAF base fluid retained on cuttings using theretort procedure (see Equations 1–5,Appendix 7 of subpart A of this part).Operators shall start the retort analyses nomore than two hours after collecting the firstindividual mass sample for the samplinginterval .

3.6 Operators shall not discharge anysample before successfully completing themass and retort analyses [i.e., mass balance



requirements (see Section 4.b, Appendix 7 ofsubpart A of this part) are satisfied].Operators shall immediately re-run the retortanalyses if the mass balance requirements(see Equation 4, Appendix 7 of subpart A ofthis part) are not within a tolerance of 5%(see Section 4.b, Equation 4, Appendix 7 ofsubpart A of this part).

4.0 Calculations

4.1 Operators shall calculate a set of masspercent NAF base fluid retained on cuttingsvalues (%BF) and mass NAF-cuttingsdischarge fractions (X) for each NAF-cuttingswaste stream (see Section 1.1 of thisaddendum) for each sampling interval (seeSection 2.4 of this addendum) using theprocedures outlined in Appendix 7 ofsubpart A of this part.

4.2 Operators shall tabulate the followingdata for each individual NAF-cuttingssample: (1) Date and time of NAF-cuttingssample collection; (2) time period of NAF-cuttings sample collection (see Section 3.1 ofthis addendum); (3) mass and volume of eachNAF-cuttings sample; (4) measured depth(feet) at NAF-cuttings sample collection (seeSection 2.2 of this addendum); (5) respectivelinear feet of hole drilled represented by theNAF-cuttings sample (feet); and (6) the drillbit diameter (inches) used to generate theNAF-cuttings sample cuttings.

4.3 Operators shall calculate a single totalmass percent NAF base fluid retained oncuttings value (%BFT) for each samplinginterval (see Section 2.4 of this addendum)using the procedures outlined in Appendix 7of Subpart A of this part.

4.4 Operators shall tabulate the followingdata for each total mass percent NAF basefluid retained on cuttings value (%BFT) foreach NAF-cuttings sampling interval: (1) Dateand starting and stopping times of NAF-cuttings sample collection and retortanalyses; (2) measured depth of well (feet) atstart of NAF-cuttings sample collection (seeSection 2.2 of this addendum); (3) respectivelinear feet of hole drilled represented by theNAF-cuttings sample (feet); (4) the drill bitdiameter (inches) used to generate the NAF-cuttings sample cuttings; and (5) annotationwhen zero discharge of NAF-cuttings isperformed.

4.5 Operators shall calculate the weightedmass ratio averaged over all NAF wellsections (%BFwell) using the proceduresoutlined in Appendix 7 of Subpart A of thispart.

4.6 Operators shall tabulate the followingdata for each weighted mass ratio averagedover all NAF well sections (%BFwell) for eachNAF well: (1) Starting and stopping dates ofNAF well sections; (2) measured depth (feet)of all NAF well sections; (3) total number ofsampling intervals (see Section 2.4 andSection 2.6 of this addendum); (4) number ofsampling intervals tabulated during any zerodischarge operations; (5) total volume of zerodischarged NAF-cuttings over entire NAFwell sections; and (6) identification ofwhether BMPs were employed (seeAddendum B of Appendix 7 of subpart A ofthis part).

Addendum B to Appendix 7 to Subpart A ofPart 435— Best Management Practices(BMPs) for use with API RecommendedPractice 13B–2

1.0 Overview of BMPs1.1 Best Management Practices (BMPs)

are inherently pollution prevention practices.BMPs may include the universe of pollutionprevention encompassing productionmodifications, operational changes, materialsubstitution, materials and waterconservation, and other such measures.BMPs include methods to prevent toxic andhazardous pollutants from reaching receivingwaters. Because BMPs are most effectivewhen organized into a comprehensive facilityBMP Plan, operators shall develop a BMP inaccordance with the requirements in thisaddendum.

1.2 The BMP requirements contained inthis appendix were compiled from severalRegional permits, an EPA guidancedocument (i.e., Guidance Document forDeveloping Best Management Practices(BMP)’’ (EPA 833–B–93–004, U.S. EPA,1993)), and draft industry BMPs. Thesecommon elements represent the appropriatemix of broad directions needed to completea BMP Plan along with specific taskscommon to all drilling operations.

1.3 Operators are not required to useBMPs if all NAF-cuttings discharges aremonitored in accordance with Appendix 7 ofSubpart A of this part.

2.0 BMP Plan Purpose and Objectives2.1 Operators shall design the BMP Plan

to prevent or minimize the generation andthe potential for the discharge of NAF fromthe facility to the waters of the United Statesthrough normal operations and ancillaryactivities. The operator shall establishspecific objectives for the control of NAF byconducting the following evaluations.

2.2 The operator shall identify anddocument each NAF well that uses BMPsbefore starting drilling operations and theanticipated total feet to be drilled with NAFfor that particular well.

2.3 Each facility component or systemcontrolled through use of BMPs shall beexamined for its NAF-waste minimizationopportunities and its potential for causing adischarge of NAF to waters of the UnitedStates due to equipment failure, improperoperation, natural phenomena (e.g., rain,snowfall).

2.4 For each NAF wastestream controlledthrough BMPs where experience indicates areasonable potential for equipment failure(e.g., a tank overflow or leakage), naturalcondition (e.g., precipitation), or othercircumstances to result in NAF reachingsurface waters, the BMP Plan shall include aprediction of the total quantity of NAF whichcould be discharged from the facility as aresult of each condition or circumstance.

3.0 BMP Plan Requirements3.1 The BMP Plan may reflect

requirements within the pollution preventionrequirements required by the MineralsManagement Service (see 30 CFR 250.300) orother Federal or State requirements andincorporate any part of such plans into theBMP Plan by reference.

3.2 The operator shall certify that its BMPPlan is complete, on-site, and available uponrequest to EPA or the NPDES Permitcontrolling authority. This certification shallidentify the NPDES permit number and besigned by an authorized representative of theoperator. This certification shall be kept withthe BMP Plan. For new or modified NPDESpermits, the certification shall be made nolater than the effective date of the new ormodified permit. For existing NPDESpermits, the certification shall be madewithin one year of permit issuance.

3.3 The BMP Plan shall:3.3.1 Be documented in narrative form,

and shall include any necessary plot plans,drawings or maps, and shall be developed inaccordance with good engineering practices.At a minimum, the BMP Plan shall containthe planning, development andimplementation, and evaluation/reevaluationcomponents. Examples of these componentsare contained in ‘‘Guidance Document forDeveloping Best Management Practices(BMP)’’ (EPA 833–B–93–004, U.S. EPA,1993).

3.3.2 Include the following provisionsconcerning BMP Plan review.

3.3.2.1 Be reviewed by permittee’sdrilling engineer and offshore installationmanager (OIM) to ensure compliance withthe BMP Plan purpose and objectives setforth in Section 2.0.

3.3.2.2 Include a statement that thereview has been completed and that the BMPPlan fulfills the BMP Plan purpose andobjectives set forth in Section 2.0. Thisstatement shall have dated signatures fromthe permittee’s drilling engineer and offshoreinstallation manager and any otherindividuals responsible for development andimplementation of the BMP Plan.

3.4 Address each component or systemcapable of generating or causing a release ofsignificant amounts of NAF and identifyspecific preventative or remedial measures tobe implemented.

4.0 BMP Plan Documentation4.1 The operator shall maintain a copy of

the BMP Plan and related documentation(e.g., training certifications, summary of themonitoring results, records of NAF-equipment spills, repairs, and maintenance)at the facility and shall make the BMP Planand related documentation available to EPAor the NPDES Permit controlling authorityupon request.

5.0 BMP Plan Modification5.1 For those NAF wastestreams

controlled through BMPs, the operator shallamend the BMP Plan whenever there is achange in the facility or in the operation ofthe facility which materially increases thegeneration of those NAF-wastes or theirrelease or potential release to the receivingwaters.

5.2 At a minimum the BMP Plan shall bereviewed once every five years and amendedwithin three months if warranted. Any suchchanges to the BMP Plan shall be consistentwith the objectives and specific requirementslisted in this addendum. All changes in theBMP Plan shall be reviewed by thepermittee’s drilling engineer and offshoreinstallation manager.



5.3 At any time, if the BMP Plan provesto be ineffective in achieving the generalobjective of preventing and minimizing thegeneration of NAF-wastes and their releaseand potential release to the receiving watersand/or the specific requirements in thisaddendum, the permit and/or the BMP Planshall be subject to modification toincorporate revised BMP requirements.

6.0 Specific Pollution PreventionRequirements for NAF DischargesAssociated with Cuttings

6.1 The following specific pollutionprevention activities are required in a BMPPlan when operators elect to control NAFdischarges associated with cuttings by a setof BMPs.

6.2 Establishing programs for identifying,documenting, and repairing malfunctioningNAF equipment, tracking NAF equipmentrepairs, and training personnel to report andevaluate malfunctioning NAF equipment.

6.3 Establishing operating andmaintenance procedures for each componentin the solids control system in a mannerconsistent with the manufacturer’s designcriteria.

6.4 Using the most applicable spacers,flushes, pills, and displacement techniquesin order to minimize contamination ofdrilling fluids when changing from water-based drilling fluids to NAF and vice versa.

6.5 A daily retort analysis shall beperformed (in accordance with Appendix 7to subpart A of Part 435) during the first 0.33X feet drilled with NAF where X is theanticipated total feet to be drilled with NAFfor that particular well. The retort analysesshall be documented in the well retort log.The operators shall use the calculationprocedures detailed in Appendix 7 to subpartA of part 435 (see Equations 1 through 8) todetermine the arithmetic average (%BFwell) ofthe retort analyses taken during the first 0.33X feet drilled with NAF.

6.5.1 When the arithmetic average(%BFwell) of the retort analyses taken duringthe first 0.33 X feet drilled with NAF is lessthan or equal to the base fluid retained on

cuttings limitation or standard (see §§ 435.13and 435.15), retort monitoring of cuttingsmay cease for that particular well. The sameBMPs and drilling fluid used during the first0.33 X feet shall be used for all remainingNAF sections for that particular well.

6.5.2 When the arithmetic average(%BFwell) of the retort analyses taken duringthe first 0.33 X feet drilled with NAF isgreater the base fluid retained on cuttingslimitation or standard (see §§ 435.13 and435.15), retort monitoring shall continue forthe following (second) 0.33 X feet drilledwith NAF where X is the anticipated totalfeet to be drilled with NAF for that particularwell. The retort analyses for the first andsecond 0.33 X feet shall be documented inthe well retort log.

6.5.2.1 When the arithmetic average(%BFwell) of the retort analyses taken duringthe first 0.66 X feet (i.e., retort analyses takenfrom first and second 0.33 X feet) drilledwith NAF is less than or equal to the basefluid retained on cuttings limitation orstandard (see §§ 435.13 and 435.15), retortmonitoring of cuttings may cease for thatparticular well. The same BMPs and drillingfluid used during the first 0.66 X feet shallbe used for all remaining NAF sections forthat particular well.

6.5.2.2 When the arithmetic average(%BFwell) of the retort analyses taken duringthe first 0.66 X feet (i.e., retort analyses takenfrom first and second 0.33 X feet) drilledwith NAF is greater than the base fluidretained on cuttings limitation or standard(see §§ 435.13 and 435.15), retort monitoringshall continue for all remaining NAF sectionsfor that particular well. The retort analysesfor all NAF sections shall be documented inthe well retort log.

6.5.3 When the arithmetic average(%BFwell) of the retort analyses taken over allNAF sections for the entire well is greaterthat the base fluid retained on cuttingslimitation or standard (see §§ 435.13 and435.15), the operator is in violation of thebase fluid retained on cuttings limitation orstandard and shall submit notification of

these monitoring values in accordance withNPDES permit requirements. Additionally,the operator shall, as part of the BMP Plan,initiate a reevaluation and modification tothe BMP Plan in conjunction with equipmentvendors and/or industry specialists.

6.5.4 The operator shall include retortmonitoring data and dates of retort-monitored and non-retort-monitored NAF-cuttings discharges managed by BMPs intheir NPDES permit reports.

6.6 Establishing mud pit and equipmentcleaning methods in such a way as tominimize the potential for building-up drillcuttings (including accumulated solids) inthe active mud system and solids controlequipment system. These cleaning methodsshall include but are not limited to thefollowing procedures.

6.6.1 Ensuring proper operation andefficiency of mud pit agitation equipment.

6.6.2 Using mud gun lines during mixingoperations to provide agitation in deadspaces.

6.6.3 Pumping drilling fluids off of drillcuttings (including accumulated solids) foruse, recycle, or disposal before using washwater to dislodge solids.

Appendix 8 to Subpart A of Part 435—Reference C16–C18 Internal Olefin DrillingFluid Formulation

The reference C16–C18 internal olefindrilling fluid used to determine the drillingfluid sediment toxicity ratio and compliancewith the BAT sediment toxicity dischargelimitation (see § 435.13) and NSPS (see§ 435.15) shall be formulated to meet thespecifications in Table 1 of this appendix.

Drilling fluid sediment toxicity ratio = 4-day LC50 of C16–C18 internal olefin drillingfluid/4-day LC50 of drilling fluid removedfrom cuttings at the solids control equipmentas determined by ASTM E1367–92[incorporated by reference and specified at§ 435.11(ee)] and supplemented with thesediment preparation procedure (Appendix 3of subpart A of this part).

TABLE 1.—PROPERTIES FOR REFERENCE C16–C18 IOS SBF USED IN DISCHARGE SEDIMENT TOXICITY TESTING

Mud weight of SBF discharged with cuttings (pounds per gallon) Reference C16–C18 IOsSBF (pounds per gallon)

Reference C16–C18 IOsSBF synthetic to water

ratio (%)

8.5–11 ...................................................................................................................................... 9.0 75/2511–14 ....................................................................................................................................... 11.5 80/20>14 ........................................................................................................................................... 14.5 85/15

Plastic Viscosity (PV), centipoise (cP) .................................................................................... 12–30Yield Point (YP), pounds/100 sq. ft ......................................................................................... 10–2010-second gel, pounds/100 sq. ft ............................................................................................ 8–1510-minute gel, pounds/100 sq. ft ............................................................................................. 12–30Electrical stability, V ................................................................................................................. >300

Subpart D—Coastal Subcategory

8. Section 435.41 is amended byrevising paragraphs (b) through (ff) andby adding paragraphs (gg) through (ii) toread as follows:

§ 435.41 Special definitions.

* * * * *(b) Average of daily values for 30

consecutive days means the average ofthe daily values obtained during any 30consecutive day period.

(c) Base fluid means the continuousphase or suspending medium of adrilling fluid formulation.

(d) Base fluid retained on cuttings asapplied to BAT effluent limitations andNSPS refers to the American PetroleumInstitute Recommended Practice 13B–2



supplemented with the specifications,sampling methods, and averagingmethod for retention values provided inAppendix 7 of subpart A of this part.

(e) Biodegradation rate as applied toBAT effluent limitations and NSPS fordrilling fluids and drill cuttings refers tothe ISO 11734:1995 method: ‘‘Waterquality—Evaluation of the ‘ultimate’anaerobic biodegradability of organiccompounds in digested sludge—Methodby measurement of the biogasproduction (1995 edition)’’ (Availablefrom the American National StandardsInstitute, 11 West 42nd Street, 13thFloor, New York, NY 10036)supplemented with modifications inAppendix 4 of subpart A of this part.

(f) Cook Inlet refers to coastallocations north of the line between CapeDouglas on the West and Port Chathamon the east.

(g) Daily values as applied toproduced water effluent limitations andNSPS means the daily measurementsused to assess compliance with themaximum for any one day.

(h) Deck drainage means any wasteresulting from deck washings, spillage,rainwater, and runoff from gutters anddrains including drip pans and workareas within facilities subject to thisSubpart.

(i) Development facility means anyfixed or mobile structure subject to thisSubpart that is engaged in the drillingof productive wells.

(j) Dewatering effluent meanswastewater from drilling fluids and drillcuttings dewatering activities (includingbut not limited to reserve pits or othertanks or vessels, and chemical ormechanical treatment occurring duringthe drilling solids separation/recycle/disposal process).

(k) Diesel oil refers to the grade ofdistillate fuel oil, as specified in theAmerican Society for Testing andMaterials Standard Specification forDiesel Fuel Oils D975–91, that istypically used as the continuous phasein conventional oil-based drilling fluids.This incorporation by reference wasapproved by the Director of the FederalRegister in accordance with 5 U.S.C.552(a) and 1 CFR part 51. Copies maybe obtained from the American Societyfor Testing and Materials, 1916 RaceStreet, Philadelphia, PA 19103. Copiesmay be inspected at the Office of theFederal Register, 800 North CapitolStreet, NW., Suite 700, Washington, DC.A copy may also be inspected at EPA’sWater Docket, 401 M Street SW.,Washington, DC 20460.

(l) Domestic waste means thematerials discharged from sinks,showers, laundries, safety showers, eye-wash stations, hand-wash stations, fish

cleaning stations, and galleys locatedwithin facilities subject to this Subpart.

(m) Drill cuttings means the particlesgenerated by drilling into subsurfacegeologic formations and carried outfrom the wellbore with the drillingfluid. Examples of drill cuttings includesmall pieces of rock varying in size andtexture from fine silt to gravel. Drillcuttings are generally generated fromsolids control equipment and settle outand accumulate in quiescent areas inthe solids control equipment or otherequipment processing drilling fluid (i.e.,accumulated solids).

(1) Wet drill cuttings means theunaltered drill cuttings and adheringdrilling fluid and formation oil carriedout from the wellbore with the drillingfluid.

(2) Dry drill cuttings means theresidue remaining in the retort vesselafter completing the retort procedurespecified in Appendix 7 of subpart A ofthis part.

(n) Drilling fluid means the circulatingfluid (mud) used in the rotary drillingof wells to clean and condition the holeand to counterbalance formationpressure. Classes of drilling fluids are:

(1) Water-based drilling fluid meansthe continuous phase and suspendingmedium for solids is a water-misciblefluid, regardless of the presence of oil.

(2) Non-aqueous drilling fluid meansthe continuous phase and suspendingmedium for solids is a water-immisciblefluid, such as oleaginous materials (e.g.,mineral oil, enhanced mineral oil,paraffinic oil, C16–C18 internal olefins,and C8–C16 fatty acid/2-ethylhexylesters).

(i) Oil-based means the continuousphase of the drilling fluid consists ofdiesel oil, mineral oil, or some other oil,but contains no synthetic material orenhanced mineral oil.

(ii) Enhanced mineral oil-basedmeans the continuous phase of thedrilling fluid is enhanced mineral oil.

(iii) Synthetic-based means thecontinuous phase of the drilling fluid isa synthetic material or a combination ofsynthetic materials.

(o) Enhanced mineral oil as applied toenhanced mineral oil-based drillingfluid means a petroleum distillatewhich has been highly purified and isdistinguished from diesel oil andconventional mineral oil in having alower polycyclic aromatic hydrocarbon(PAH) content. Typically, conventionalmineral oils have a PAH content on theorder of 0.35 weight percent expressedas phenanthrene, whereas enhancedmineral oils typically have a PAHcontent of 0.001 or lower weight percentPAH expressed as phenanthrene.

(p) Exploratory facility means anyfixed or mobile structure subject to thisSubpart that is engaged in the drillingof wells to determine the nature ofpotential hydrocarbon reservoirs.

(q) Formation oil means the oil froma producing formation which is detectedin the drilling fluid, as determined bythe GC/MS compliance assurancemethod specified in Appendix 5 ofsubpart A of this part when the drillingfluid is analyzed before being shippedoffshore, and as determined by the RPEmethod specified in Appendix 6 ofsubpart A of this part when the drillingfluid is analyzed at the offshore point ofdischarge. Detection of formation oil bythe RPE method may be confirmed bythe GC/MS compliance assurancemethod, and the results of the GC/MScompliance assurance method shallsupercede those of the RPE method.

(r) Garbage means all kinds of victual,domestic, and operational waste,excluding fresh fish and parts thereof,generated during the normal operationof coastal oil and gas facility and liableto be disposed of continuously orperiodically, except dishwater,graywater, and those substances that aredefined or listed in other Annexes toMARPOL 73/78. A copy of MARPOLmay be inspected at EPA’s WaterDocket; 401 M Street SW., WashingtonDC 20460.

(s) M9IM means those offshorefacilities continuously manned by nine(9) or fewer persons or onlyintermittently manned by any numberof persons.

(t) M10 means those offshore facilitiescontinuously manned by ten (10) ormore persons.

(u) Maximum as applied to BATeffluent limitations and NSPS fordrilling fluids and drill cuttings meansthe maximum concentration allowed asmeasured in any single sample of thebarite for determination of cadmiumand mercury content.

(v) Maximum for any one day asapplied to BPT, BCT and BAT effluentlimitations and NSPS for oil and greasein produced water means the maximumconcentration allowed as measured bythe average of four grab samplescollected over a 24-hour period that areanalyzed separately. Alternatively, forBAT and NSPS the maximumconcentration allowed may bedetermined on the basis of physicalcomposition of the four grab samplesprior to a single analysis.

(w) Minimum as applied to BATeffluent limitations and NSPS fordrilling fluids and drill cuttings meansthe minimum 96-hour LC50 valueallowed as measured in any singlesample of the discharged waste stream.



Minimum as applied to BPT and BCTeffluent limitations and NSPS forsanitary wastes means the minimumconcentration value allowed asmeasured in any single sample of thedischarged waste stream.

(x)(1) New source means any facilityor activity of this subcategory that meetsthe definition of ‘‘new source’’ under 40CFR 122.2 and meets the criteria fordetermination of new sources under 40CFR 122.29(b) applied consistently withall of the following definitions:

(i) Water area as used in ‘‘site’’ in 40CFR 122.29 and 122.2 means the waterarea and water body floor beneath anyexploratory, development, orproduction facility where such facilityis conducting its exploratory,development or production activities.

(ii) Significant site preparation workas used in 40 CFR 122.29 means theprocess of surveying, clearing orpreparing an area of the water bodyfloor for the purpose of constructing orplacing a development or productionfacility 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.

(y) No discharge of free oil means thatwaste streams may not be dischargedthat contain free oil as evidenced by themonitoring method specified for thatparticular stream, e.g., deck drainage ormiscellaneous discharges cannot bedischarged when they would cause afilm or sheen upon or discoloration ofthe surface of the receiving water;drilling fluids or cuttings may not bedischarged when they fail the staticsheen test defined in Appendix 1 ofsubpart A of this part.

(z) Parameters that are regulated inthis subpart and listed with approvedmethods of analysis in Table 1B at 40CFR 136.3 are defined as follows:

(1) Cadmium means total cadmium.(2) Chlorine means total residual

chlorine.(3) Mercury means total mercury.(4) Oil and Grease means total

recoverable oil and grease.(aa) Produced sand means the slurried

particles used in hydraulic fracturing,the accumulated formation sands andscales particles generated duringproduction. Produced sand alsoincludes desander discharge from the

produced water waste stream, andblowdown of the water phase from theproduced water treating system.

(bb) Produced water means the water(brine) brought up from thehydrocarbon-bearing strata during theextraction of oil and gas, and caninclude formation water, injectionwater, and any chemicals addeddownhole or during the oil/waterseparation process.

(cc) Production facility means anyfixed or mobile structure subject to thissubpart that is either engaged in wellcompletion or used for active recoveryof hydrocarbons from producingformations. It includes facilities that areengaged in hydrocarbon fluidsseparation even if located separatelyfrom wellheads.

(dd) Sanitary waste means the humanbody waste discharged from toilets andurinals located within facilities subjectto this subpart.

(ee) SPP toxicity as applied to BATeffluent limitations and NSPS fordrilling fluids and drill cuttings refers tothe bioassay test procedure presented inAppendix 2 of subpart A of this part.

(ff) Static sheen test means thestandard test procedure that has beendeveloped 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 of subpart A of this part.

(gg) Stock barite means the barite thatwas used to formulate a drilling fluid.

(hh) Synthetic material as applied tosynthetic-based drilling fluid meansmaterial produced by the reaction ofspecific purified chemical feedstock, asopposed to the traditional base fluidssuch as diesel and mineral oil which arederived from crude oil solely throughphysical separation processes. Physicalseparation processes includefractionation and distillation and/orminor chemical reactions such ascracking and hydro processing. Sincethey are synthesized by the reaction ofpurified compounds, synthetic materialssuitable for use in drilling fluids aretypically free of polycyclic aromatichydrocarbons (PAH’s) but aresometimes found to contain levels ofPAH up to 0.001 weight percent PAHexpressed as phenanthrene. Internalolefins and vegetable esters are twoexamples of synthetic materials suitable

for use by the oil and gas extractionindustry in formulating drilling fluids.Internal olefins are synthesized from theisomerization of purified straight-chain(linear) hydrocarbons such as C16–C18

linear alpha olefins. C16–C18 linear alphaolefins are unsaturated hydrocarbonswith the carbon to carbon double bondin the terminal position. Internal olefinsare typically formed from heating linearalpha olefins with a catalyst. The feedmaterial for synthetic linear alphaolefins is typically purified ethylene.Vegetable esters are synthesized fromthe acid-catalyzed esterification ofvegetable fatty acids with variousalcohols. EPA listed these two branchesof synthetic fluid base materials toprovide examples, and EPA does notmean to exclude other syntheticmaterials that are either in current useor may be used in the future. Asynthetic-based drilling fluid mayinclude a combination of syntheticmaterials.

(ii) Well completion fluids means saltsolutions, weighted brines, polymers,and various additives used to preventdamage to the well bore duringoperations which prepare the drilledwell for hydrocarbon production.

(jj) Well treatment fluids means anyfluid used to restore or improveproductivity by chemically orphysically altering hydrocarbon-bearingstrata after a well has been drilled.

(kk) Workover fluids means saltsolutions, weighted brines, polymers, orother specialty additives used in aproducing well to allow formaintenance, repair or abandonmentprocedures.

(ll) 96-hour LC50 means theconcentration (parts per million) orpercent 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.

9. In § 435.42 the table is amended byremoving the entries ‘‘Drilling fluids’’and ‘‘Drill cuttings’’ and by adding newentries (after ‘‘Deck drainage’’) for‘‘Water based’’ and ‘‘Non-aqueous’’ toread as follows:

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

* * * * *



BPT EFFLUENT LIMITATIONS—OIL AND GREASE

[In milligrams per liter]

Pollutant parameter waste source Maximum for any 1 day Average of values for 30 con-secutive days shall not exceed

Residualchlorineminimumfor any 1

day

* * * * * * *Water-based:

Drilling fluids .......................................................................... ( 1) .............................................. ( 1) .............................................. NADrill Cuttings .......................................................................... ( 1) .............................................. ( 1) .............................................. NA

Non-aqueous:Drilling fluids .......................................................................... No discharge ............................. No discharge ............................. NADrill Cuttings .......................................................................... ( 1) .............................................. ( 1) .............................................. NA

* * * * * * *

1 No discharge of free oil.

* * * * *

10. In § 435.43 the table is amended by revising entry (B) under ‘‘Drilling fluids, drill cuttings, and dewateringeffluent’’ and by revising footnote 4 and adding footnote 5 to read as follows:

§ 435.43 Effluent limitations guidelines representing the degree of effluent reduction attainable by the application of the best availabletechnology economically achievable (BAT).

* * * * *

BAT EFFLUENT LIMITATIONS


* * * * * * *Drilling fluids, Drill cuttings, and

Dewatering effluent: 1

* * * * * * *(B) Cook Inlet:

Water-based drilling fluids, drillcuttings, and dewatering ef-fluent.

SPP Toxicity .................................. Minimum 96-hour LC50 of the SPP Toxicity Test 4 shall be 3% by vol-ume.

Free oil ........................................... No discharge.2Diesel oil ........................................ No discharge.Mercury .......................................... 1 mg/kg dry weight maximum in the stock barite.Cadmium ........................................ 3 mg/kg dry weight maximum in the stock barite.

Non-aqueous drilling fluidsand dewatering effluent.

................................................... No discharge.

Drill cuttings associated withnon-aqueous drilling fluids.

................................................... No discharge.5

* * * * * * *

1 BAT limitations for dewatering effluent are applicable prospectively. BAT limitations in this rule are not applicable to discharges of dewateringeffluent from reserve pits which as of the effective date of this rule no longer receive drilling fluids and drill cuttings. Limitations on such dis-charges shall be determined by the NPDES permit issuing authority.

2 As determined by the static sheen test (see Appendix 1 of Subpart A of this part).* * * * * * *4 As determined by the suspended particulate phase (SPP) toxicity test (see Appendix 2 of Subpart A of this part).5 When Cook Inlet operators cannot comply with this no discharge requirement due to technical limitations (see Appendix 1 of Subpart D of this

part), Cook Inlet operators shall meet the same stock limitations (C16-C18 internal olefin) and discharge limitations for drill cuttings associated withnon-aqueous drilling fluids for operators in Offshore waters (see § 435.13) in order to discharge drill cuttings associated with non-aqueous drillingfluids.

11. In § 435.44 the table is amendedby revising the entry for ‘‘Cook Inlet’’under the entry for ‘‘Drilling fluids anddrill cuttings and dewatering effluent’’to read as follows:

§ 435.44 Effluent limitations guidelinesrepresenting the degree of effluentreduction attainable by the application ofthe best conventional pollutant controltechnology (BCT).* * * * *



BCT EFFLUENT LIMITATIONS


* * * * * * *Drilling fluids, Drill cuttings, and Dewatering effluent: 1

* * * * * * *Cook Inlet:

Water-based drilling fluids, drill cuttings, and dewateringeffluent.

Free Oil ................................................................................... No discharge.2

Non-aqueous drilling fluids and dewatering effluent ....... ............................................................................................ No discharge.Drill cuttings associated with non-aqueous drilling fluids Free Oil ................................................................................... No discharge.2

1 BCT limitations for dewatering effluent are applicable prospectively. BCT limitations in this rule are not applicable to discharges of dewateringeffluent from reserve pits which as of the effective date of this rule no longer receive drilling fluids and drill cuttings. Limitations on such dis-charges shall be determined by the NPDES permit issuing authority.

2 As determined by the static sheen test (see Appendix 1 of Subpart A of this part).

* * * * *12. In § 435.45 the table is amended

by revising entry (B) under ‘‘Drilling

fluids, drill cuttings, and dewateringeffluent’’ and by revising footnote 4 andadding footnote 5 to read as follows:

§ 435.45 Standards of performance fornew sources (NSPS).

* * * * *

NEW SOURCE PERFORMANCE STANDARDS (NSPS)

Waste Source Pollutant parameter NSPS

* * * * * * *

Drilling fluids, Drill cuttings, andDewatering effluent: 1

* * * * * * *

(B) Cook Inlet:Water-based drilling fluids, drill

cuttings, and dewatering ef-fluent.

SPP Toxicity .................................. Minimum 96-hour LC50 of the SPP Toxicity Test 4 shall be 3% by vol-ume.

Free oil ........................................... No discharge.2Diesel oil ........................................ No discharge.Mercury .......................................... 1 mg/kg dry weight maximum in the stock barite.Cadmium ........................................ 3 mg/kg dry weight maximum in the stock barite.

Non-aqueous drilling fluidsand dewatering effluent.

................................................... No discharge.

Drill cuttings associated withnon-aqueous drilling fluids.

................................................... No discharge.5

* * * * * * *

1 NSPS for dewatering effluent are applicable prospectively. NSPS in this rule are not applicable to discharges of dewatering effluent from re-serve pits which as of the effective date of this rule no longer receive drilling fluids and drill cuttings. Limitations on such discharges shall be de-termined by the NPDES permit issuing authority.

2 As determined by the static sheen test (see Appendix 1 of subpart A of this part).* * * * * * *4 As determined by the suspended particulate phase (SPP) toxicity test (see Appendix 2 of subpart A of this part).5 When Cook Inlet operators cannot comply with this no discharge requirement due to technical limitations (see Appendix 1 of subpart D of this

part), Cook Inlet operators shall meet the same stock limitations (C16–C18 internal olefin) and discharge limitations for drill cuttings associatedwith non-aqueous drilling fluids for operators in Offshore waters (see § 435.15) in order to discharge drill cuttings associated with non-aqueousdrilling fluids.

13. Subpart D is amended by addingAppendix 1 as follows:

Appendix 1 to Subpart D of Part 435—Procedure for Determining WhenCoastal Cook Inlet Operators Qualifyfor an Exemption from the ZeroDischarge Requirement for EMO-Cuttings and SBF-Cuttings in CoastalCook Inlet, Alaska

1.0 Scope and Application

This appendix is to be used to determinewhether a Cook Inlet, Alaska, operator in

Coastal waters (Coastal Cook Inlet operator)qualifies for the exemption to the zerodischarge requirement established by 40 CFR435.43 and 435.45 for drill cuttingsassociated with the following non-aqueousdrilling fluids: enhanced mineral oil baseddrilling fluids (EMO-cuttings) and synthetic-based drilling fluids (SBF-cuttings). CoastalCook Inlet operators are prohibited fromdischarging oil-based drilling fluids. Thisappendix is intended to define thosesituations under which technical limitations



preclude Coastal Cook Inlet operators fromcomplying with the zero dischargerequirement for EMO-cuttings and SBF-cuttings. Coastal Cook Inlet operators thatqualify for this exemption may be authorizedto discharge EMO-cuttings and SBF-cuttingssubject to the limitations applicable tooperators in Offshore waters (see subpart Aof this part).

2.0 Method2.1 Any Coastal Cook Inlet operator must

achieve the zero discharge limit for EMO-cuttings and SBF-cuttings unless itsuccessfully demonstrates that technicallimitations prevent it from being able todispose of its EMO-cuttings or SBF-cuttingsthrough on-site annular disposal, injectioninto a Class II underground injection control(UIC) well, or onshore land application.

2.2 To successfully demonstrate thattechnical limitations prevent it from beingable to dispose of its EMO-cuttings or SBF-cuttings through on-site annular disposal, aCoastal Cook Inlet operator must show thatit has been unable to establish formationinjection in nearby wells that were initiallyconsidered for annular or dedicated disposalof EMO-cuttings or SBF-cuttings or prove tothe satisfaction of the Alaska Oil and GasConservation Commission (AOGCC) that theEMO-cuttings or SBF-cuttings will beconfined to the formation disposal interval.This demonstration must include:

a. Documentation, including engineeringanalysis, that shows (1) an inability toestablish formation injection (e.g., formationis too tight), (2) an inability to confine EMO-cuttings or SBF-cuttings in disposalformation (e.g., no confining zone oradequate barrier to confine wastes information), or (3) the occurrence of high risk

emergency (e.g., mechanical failure of well,loss of ability to inject that risks loss of wellwhich would cause significant economicharm or create a substantial risk to safety);and

b. A risk analysis of alternative disposaloptions, including environmentalassessment, human health and safety, andeconomic impact, that shows discharge as thelowest risk option.

2.3 To successfully demonstrate thattechnical limitations prevent it from beingable to dispose of its EMO-cuttings or SBF-cuttings through injection into a Class II UICwell, a Coastal Cook Inlet operator mustshow that it has been unable to establishinjection into a Class II UIC well or prove tothe satisfaction of the Alaska Oil and GasConservation Commission (AOGCC) that theEMO-cuttings or SBF-cuttings will beconfined to the formation disposal interval.This demonstration must include:

a. Documentation, including engineeringanalysis, that shows the inability to confineEMO-cuttings or SBF-cuttings in a Class IIUIC well (e.g., no confining zone or adequatebarrier to confine wastes in formation);

b. Documentation demonstrating that noClass II UIC well is accessible (e.g., operatordoes not own, competitor will not allowinjection); and

c. A risk analysis of alternative disposaloption, including environmental assessment,human health and safety, and economicimpact, that shows discharge as the lowestrisk option.

2.4 To successfully demonstrate thattechnical limitations prevent it from beingable to dispose of its EMO-cuttings or SBF-cuttings through land application, a CoastalCook Inlet operator must show that it hasbeen unable to handle drilling waste or

dispose of EMO-cuttings or SBF-cuttings atan appropriate land disposal site. Thisdemonstration must include:

a. Documentation of site restrictions thatpreclude land application (e.g., no landdisposal sites available);

b. Documentation of the platform’s lack ofcapacity for adequate storage of EMO-cuttings or SBF-cuttings (e.g., limited storageor room for cuttings transfer); or

c. Documentation of inability to transferEMO-cuttings or SBF-cuttings from platformto land for disposal (e.g., extremely low tides,high wave action).

3.0 Procedure

3.1 Except as described in Section 3.2 ofthis appendix, a Coastal Cook Inlet operatorbelieving that it qualifies for the exemptionto the zero discharge requirement for EMO-cuttings or SBF-cuttings must apply for andobtain an individual NPDES permit prior todischarging EMO-cuttings or SBF-cuttings towaters of the United States.

3.2 Discharges occurring as the result ahigh risk emergency (e.g., mechanical failureof well, loss of ability to inject that risks lossof well which would cause significanteconomic harm or safety) may be authorizedby a general NPDES permit provided that:

a. The Coastal Cook Inlet operatorsatisfactorily demonstrates to EPA Region 10the fulfillment of the other exemptionrequirements described in Section 2.0 of thisappendix, or

b. The general permit allows for high riskemergency discharges and providesReporting Requirements to EPA Region 10immediately upon commencing discharge.[FR Doc. 01–361 Filed 1–19–01; 8:45 am]BILLING CODE 6560–50–U


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