Federal Register Vol. 53, No. 204 Friday, October 21, 1988

Federal Register / Vol. 53, No. 204 / Friday, October 21, 1988 / Proposed Rules

Executive Order 12612, and it has beendetermined not to have any federalismimplication that warrants thepreparation of a federalism assessment.

List of Subjects in 14 CFR Part 399

Applicability and effects, Operatingauthority, Rates and tariffs; Accountsand reports, Hearing matters,Rulemaking prosecutions, Enforcement,Other policies, Disclosure ofinformation, Federal preemption.

Accordingly, the Department ofTransportation (DOT) proposes toamend 14 CFR Part 399 as follows:

PART 399-STATEMENT OF GENERALPOLICY

1. The authority citation for Part 399would continue to read as follows:

Authority: 101, 102, 105, 204, 401, 402, 403,404, 405, 406, 407, 408, 411, 412, 414, 416, 801,1001, 1002, 1102, 1104, Pub. L. 85-726, asamended, 72 Stat. 737, 740, 92 Stat. 1708, 72Stat. 743, 754, 757, 758, 7670, 763, 766, 767, 768,769, 770, 771, 782, 788, 7979, 49 U.S.C. 1301,1302, 1305, 1324, 1371, 1372, 1373, 1374, 1375,1376, 1377, 1378, 1379, 1381, 1382, 1384, 1386,1461, 1481, 1482, 1502, 1504; Pub. L. 96-354, 5U.S.C. 601, unless otherwise noted.

2. Add a new § 399.85 to Subpart Q toread as follows:

§ 399.85 Enforcement policy regardingillegal rebating In foreign air transportation.

(a) It is the policy of the Departmentto review complaints alleging illegalrebating in foreign air transportation ona case-by-case basis to determinewhether it is in the public interest andconsistent with the Department'stransportation policy goals to initiate aninvestigation or to bring enforcementaction on the Department's behalf.

(b) An investigation or otherenforcement action may be undertakenonly when clear evidence is presentedthat rebating in violation of section403(b) of the Act has occurred and thatsuch rebating is adversely affecting asubstantial number of persons and is:

(1] Occurring in connection withfraudulent or deceptive practicesassociated with the holding out or saleof fares or rates involving a rebate, or

(2) Offered on an invidiouslydiscriminatory basis such as rebateslimited on the basis of race, creed, color,sex, religious or political affiliation, ornational origin, or

(3) Adversely affecting competitionbecause the rebates are associated withactivities that violate the antitrust laws.

(c] For purposes of this policy, arebate may be found to be connectedwith fraudulent or deceptive practiceswhere, for example, a rebate is offeredin connection with a "bait-and-switch"

scheme whereby the seller uses therebate offer to attract a client and thenpressures the customer to purchase ahigher-fare ticket.

(d) For purposes of this policy arebate offer will not be found to affectcompetition adversely when the onlyeffect of the offer is to divert passengersfrom one airline or ticket seller toanother.

§ 399.80 [Amended]3. Remove and reserve paragraph

399.80(g) in its entirety.4. Remove and reserve paragraph

399.80(h) in its entirety.Issued in Washington, DC, on October 17,

1988.Jim Burnley,Secretary of Transportation.[FR Doc. 88-24241 Filed 10-20-88; 8:45 am]BILLING CODE 4910-62-M

ENVIRONMENTAL PROTECTION

AGENCY

40 CFR Part 435[FRL-3463-7]Oil and Gas Extraction Point SourceCategory, Offshore Subcategory;Effluent Limitations Guidelines andNew Source Performance Standards;New Information and Request forComments

AGENCY: Envirommental ProtectionAgency (EPA).ACTION: Notice of data availability andrequest for comments.

SUMMARY: EPA is announcing today theavailability for public comment of newtechnical, economic and environmentalassessment information relating to thedevelopment of BAT and NSPSregulations under the Clean Water Actgoverning the discharge of drilling fluidsand drill cuttings in the oil and gasextraction point source category,offshore subcategory. EPA requestscomment on this new information. Thisnotice is part of a rulemaking processthat commenced formally on August 26,1985 with EPA's proposal of effluentlimitations guidelines and new sourceperformance standards for the offshoresubcategory (50 FR 34592). The commentperiod for the original proposal closedon March 15, 1986.DATE: Comments on this newinf6rmation must be submitted byDecember 5, 1988.ADDRESSES: Comments should be sentto Mr. Dennis Ruddy, IndustrialTechnology Division (WH-552),Environmental Protection Agency, 401 MStreet SW., Washington, DC 20460.

The supporting information and datadescribed in this notice will be availablefor inspection and copying at the EPAPublic Information Reference Unit,Room 2402 (Rear of EPA Library) PM-231, 401 M Street SW., Washington, DC20460. The EPA public informationregulation (40 CFR Part 2) provides thata reasonable fee may be charged forcopying.

FOR FURTHER INFORMATION CONTACT:Technical information may be obtainedfrom Mr. Dennis Ruddy at the aboveaddress, or call (202) 382-7131.Economic information may be obtainedfrom Ms. Ann Watkins, EconomicAnalysis Branch (WH-586), at the aboveaddress or call (202) 382-5387.Environmental assessment informationmay be obtained from Ms. AlexandraTarnay, Monitoring and Data SupportDivision (WH-553), at the aboveaddress or call (202) 382-7036.

SUPPLEMENTARY INFORMATION: On

August 26, 1985, EPA proposed effluentlimitations guidelines and new sourceperformance standards for the oil andgas extraction point source category,offshore subcategory, 50 FR 34592. Theproposal included BAT, BCT, and NSPSregulations covering produced water,drilling fluids, drill cuttings, producedsand, deck drainage, well treatmentfluids and sanitary and domestic wastedischarges from offshore oil and gasfacilities. Since issuing the August 26,1985 proposal, the Agency has receivedcomments and collected additional dataon numerous aspects of this rulemaking.

Today's notice relates to thedevelopment of BAT and NSPSregulations governing the discharge ofdrilling fluids and drill cuttings. EPA isannouncing today the availability forpublic comment of new technical,economic and environmentalassessment information relating to theregulation of those waste streams. Thisnotice presents a variation on theoriginally proposed BAT and NSPSlimitations on the mercury and cadmiumcontent of discharged drilling fluids. Italso describes EPA's initial investigationof an oil content limitation that could beapplied to drilling waste streams at theBAT and NSPS levels of control.

The Agency has determined that itwill promulgate the final regulations forthe offshore subcategory in phases.Discharge regulations for drilling fluidsand drill cuttings are scheduled forpromulgation first. Regulationsgoverning the other waste streams thatwere included in the August 26, 1985proposal will be addressed in separateFederal Register notices. The Agencyintends, in the next several months, to

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issue an additional Federal Registernotice reproposing BCT effluentlimitations guidelines for drilling fluidsand drill cuttings.

Today's notice is organized asfollows:

Summary of Part 1

Summary of Part 2

Part II. Summary of Proposed Regulations

A. Drilling FluidsB. Drill Cuttings

H. New Technical Information Related to theProposed BAT/NSPS Regualtions

A. Drilling Fluid Toxicity TestB. Discharge of Oil in Water-Based Drilling

FluidsC. Analytical Method for Diesel Oil

DetectionD. Metals Limitations

Ill. Changes to Costing Data andAssumptions for Estimates of EconomicImpacts

A. Toxicity Failure Rate for Water-BasedDrilling Fluids

B. Annual Rate of DevelopmentC. Model Well CharacteristicsD. Transportation and DisposalE. Use of Oil-Based and Water-Based

Drilling FluidsF. Cost Differential Between Diesel and

Mineral OilsG. Pollutant Reduction EstimatesH. Failure Rate for "No Discharge of Free

Oil" LimitationI. Monitoring Costs

IV. Revised Industry Profile and EconomicAnalyses

A. Industry ProfileB. Economic ImpactsC. Cost-Effectiveness

V. Environmental Assessment InformationA. Mercury and Cadmium in Barite and

Environmental Consequences on AquaticLife

B. Analysis of Shallow Water DispersionModels

Port 21. Summary11. BackgroundIll. Description of Technologies for

Controlling Oil Content of DrillingWastes

IV. Applicability of Thermal and SolventExtraction Technologies for TreatingDrilling Wastes

A. Drill CuttingsB. Drilling Fluids

V. Pollutant Reduction and Cost EstimatesA. Pollutant ReductionB. Operating CostsC. Drill Cuttings from Oil- and Water-

Based Drilling FluidsD. Water-Based Drilling FluidsE. Comparison of Onsite Treatment Costs

with Onshore Disposal Costs for DrillingWastes

VI. Performance DataA. Field SamplingB. Observations and Sampling Results

VIL Oil Content of Untreated Drilling WastesA. Drill CuttingsB. Water-Based Drilling Fluids

VIII. Analytical Method.for Total Oil ContentIX. Request for CommentsAppendix A-Proposed Method 1651, Oil

Content and Diesel Oil in Drilling Mudsand Drill Cuttings by Retort Gravimetryand GCFID

Summary of Part 1

Part I of today's notice announces theavailability of additional informationand presents discussion and preliminaryconclusions on new data concerningBAT and NSPS controls on the drillingfluids and drill cuttings waste streams. Italso discusses the potential applicabilityof several computer models to analyzethe dispersion of drilling fluids andproduced water waste streams.

Part 1 begins, in Section I, with asummary of the portions of the August26, 1985 proposal that are pertinent tomaterial presented in today's notice.The discussion that follows in SectionsII, III, IV and V deals first with technicalissues, then with economic and costissues, and finally with environmentalassessment issues relating to BAT andNSPS controls on drilling fluids and drillcuttings.

Subpart A of Section III ("DrillingFluid Toxicity Test") discusses theproposed analytical method fordetermining the toxicity of drillingfluids. The discussion summarizes majorindustry comments on reliability andvariability of the proposed toxicity testmethod and presents the Agency's plansfor further evaluation of the test method.

In Subpart B of Section II ("Dischargeof Oil in Water-Based Fluids"), theAgency presents new informationrelating to its proposal to prohibit thedischarge of detectable amounts ofdiesel oil in drilling fluids and drillcuttings. Industry commenters haveargued that the discharge of diesel oilshould not be prohibited because dieseloil is the most effective agent for use infreeing stuck drill pipe. The discussionsummarizes three studies of the relativeeffectiveness of diesel oil and mineraloil for freeing stuck pipe (the 1983-1984API Survey, the 1986 Offshore OperatorsCommittee Survey and the 1986-1987EPA/API Diesel Pill MonitoringProgram). It also presents and explainsthe Agency's renewed determination, inlight of this new data, that the proposedprohibition on the discharge of diesel oilin detectable amounts continues to beappropriate for the BAT and NSPSlevels of control. Subpart C of Section II("Analytical Method for Oil Detection")and Appendix A of this notice present aproposed modification to the originallyproposed analytical method for thedetection of diesel oil 'in drilling fluidsand drill cuttings.

In Subpart D of Section II ("MetalsLimitations"), the Agency is presentingtwo sets of mercury and cadmiumeffluent limitations that may be'applicable to discharged drilling fluids.The Agency formulated a second set ofeffluent limitations for mercury andcadmium based upon informationsubmitted by commenters in response tothe set of effluent limitations presentedand discussed in the proposedregulations.

Economic and costing issues arepresented in Sections III and IV of Part1. The Agency has recosted compliancewith the proposed BAT and NSPSregulations governing the discharge ofdrilling fluids and drill cuttings basedupon new technical and costinformation. Section III summarizes thechanges to the costing information andassumptions.'Section IV presents asummary of the economic impactanalysis revised according to the newinformation and assumptions.

Under the subpart of Section III titled"Toxicity Failure Rate for DrillingFluids," the Agency presents new dataand preliminary conclusions concerningindustry's expected rate of failure of theproposed toxicity limitation (30,000 ppmsuspended particulate phase basis) bydrilling fluids that contain no added oil.This discussion also includes theAgency's revised estimate of the annualindustry cost of compliance with thetoxicity limitation for drilling fluids.• The remaining subparts of Section IIIpresent updated or refined informationthat affects various factors used inestimating annual compliance costs. Theaffected factors are the estimate ofthe number of wells to be drilledoffshore per year, model wellcharacteristics, transportation anddisposal on shore of drilling wastes thatdo not comply with the proposedlimitations and standards, the frequencyof use of bil based muds as opposed towater based muds, the cost differentialbetween diesel oil and mineral oil,pollutant reduction estimates, expectedfailure rates for the static sheen test andmonitoring costs.

Utilizing the new information andassumptions presented in Section III,Section IV summarizes the revisedindustry profile, economic impacts andother economic information concerningthe -proposed BAT and NSPS controls ondrilling fluids and drill cuttings. SectionIV also explains the Agency'spreliminary conclusion that despite'overall higher costs since proposal, therevised estimates of cost areeconomically achievable.

Finally, Section V summarizes aliterature search concerning -mercLry

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and cadmium in barite, a constituent ofdrilling fluids, and the environmentalconsequences of the discharge of drillingfluids containing barite. Section Vconcludes with the Agency's evaluationof several computer models that havepotential application in the prediction ofdispersion of discharged drilling wastesand produced water.

Summary of Part 2Part 2 of today's notice presents new

information on the performance, costsand applicability of certain thermaltechnologies and solvent extractiontechnologies for treating drilling fluidsand drill cuttings to reduce their oilcontent. Based on this information, theagency has begun to consider an oilcontent limitation of up to 1% by weight,whole sample basis, governing thedischarge of drill cuttings wastes at theBAT and NSPS levels of control.

Sections I through III of Part 2summarize the Agency's preliminarydeterminations regarding theapplicability of an oil content limitationto drilling waste streams, discuss theregulatory background giving rise toEPA's investigation of this regulatoryoption, and present an overview of thethermal distillation, thermal oxidationand solvent extraction treatmenttechnologies that are under review bythe Agency.

Section IV of Part 2 describes thesetechnologies in greater detail. Section Vdiscusses in greater detail the potentialapplicability of these technologies todrill cuttings and drilling fluids,concluding that the technologies appearsuitable as the basis for regulation ofdrill cuttings but not drilling fluids.Section VI presents preliminaryestimates of pollutant reductions andthe costs associated with treatment ofdrill cuttings and drilling fluids usingthese technologies. Section VII presentsperformance data for one variety of thethermal distillation technology. SectionVIII estimates the quantities of drillcuttings and water-based drilling fluidsthat would not meet an oil contentlimitation of 1% or less. Section IXpresents EPA's preliminary conclusionthat the revised analytical methodpresented in Appendix A is appropriatefor quantification of oil content of drillcuttings and drilling fluids. Section Xrequests comment on issues pertainingto development of BAT and NSPS oilcontent controls for drill cuttings.

The Agency is inviting comment onlyon the information presented today andregulatory approaches relevant to BATand NSPS effluent limitations for thedrilling fluids and drill cuttings wastestreams, and not on other aspects of theAugust 26, 1985 proposed rule.

The Agency intends, in the nextseveral months to issue an additionalFederal Register notice related to thisrulemaking for the drilling fluids anddrill cuttings waste streams. The topicsof the future notice are expected toinclude: Reproposal of BCT effluentlimitations guidelines, results andconclusions from the drilling fluidstoxicity test variability study(mentioned in Section II of Part I oftoday's notice), and other data oroptions that have not been addressed inFederal Register notices prior to thattime.

Part 1

I. Summary of Proposed Regulations

On August 26, 1985, EPA proposedregulations to control the discharge ofwastewater pollutants from the offshoreoil and gas extraction industry, asubcategory of the oil and gas extractioncategory (50 FR 34592) (the "1985proposal"). the proposed regulationsincluded NSPS and effluent limitationsguidelines based upon BAT and BCT.The proposed regulations also includedan amendment to the BPT definition of"no discharge of free oil." The wastestreams covered by the proposedregulations were produced water,drilling fluids, drill cuttings, deckdrainage, well treatment fluids,produced sand and sanitary anddomestic wastes.

The notice of proposed rulemakingand the supporting rulemaking recordfully explain the proposal for all of thewaste streams. For tile purposes of thispart of today's notice, a summary of theproposed regulations regarding onlydrilling fluids and drill cuttings iscontained below.

A. Drilling Fluids

1. BAT. The proposed BAT regulationsfor drilling fluids would prohibit thedischarge of free oil as measured by thestatic sheen test. The static sheen testwould provide for a determination of thepresence of free oil prior to discharge.The static sheen test method wasincluded in the proposed regulations asan appendix (50 FR 34627). The pollutantparameter free oil was proposed to beregulated as a BAT "indicator" pollutantfor control of the discharge of prioritypollutants based upon informationgathered on the concentration of prioritypollutants in both drilling fluids and thespecific additives used in the drillingfluid formulations. The parameter freeoil is proposed to be used as anindicator pollutant for priority pollutantsbecause it would be technologicallyinfeasible to develop effluent limitationsfor all of the individual priority

pollutants. The priority pollutants thatwould be controlled include benzene,toluene, ethylbenzene and naphthalene.The Agency has determined that theprohibition on the discharge of free oilas measured .by the proposed staticsheen test method would result in BAT-level control for the toxics of concern indrilling wastes.

The proposed "no discharge of freeoil" limitation differs from the current 40CFR Part 435 requirement (BPT) that isbased upon the application of bestpracticable control technology currentlyavailable (BPT). The current BPTrequirement prohibits the discharge offree oil that would "cause a film orsheen upon or a discoloration on thesurface of the water or adjoiningshorelines or cause a sludge or emulsionto be deposited beneath the surface ofthe water or upon adjoining shorelines".40 CFR 435.11(d). The compliancemonitoring procedure is a visualinspection of the receiving water afterdischarge.

The BPT limitation of "no discharge offree oil" was originally intended toprohibit the discharge of drilling wastesthat, when discharged, would cause asheen on the receiving water. Thislimitation and the current definitionwere established to be consistent withthe oil discharge provisions of section311 of the Clean Water Act. The Agencydid not intend that discharged drillingfluids be considered "sludge". For thisreason, the Agency proposed in theAugust 26, 1985, notice to amend thecurrent definition for the purposes ofBPT, BAT, BCT and NSPS by excludinglanguage that prohibits the deposition ofsludge beneath the surface of thereceiving water. This would allow thedischarge of drilling fluids, provided thatother effluent limitations are met.

The proposed regulations would alsoprohibit the discharge of diesel oil indetectable amounts. The analyticalmethod for detection of diesel oil wasincluded in the proposed regulations asan appendix (50 FR 34628). The pollutantparameter diesel oil was also proposedto be regulated as a BAT "indicator"pollutant for.control of the discharge ofpriority pollutants contained in dieseloil.

In the preamble to the 1985 proposedregulations, the Agency recognized thatdiesel oil should be regulated at the BATlevel because it contains toxic organicpollutants. Diesel oil was proposed to bedesignated an indicator pollutant for theBAT and NSPS levels to control theamounts of the individual toxic organicpollutants that it contains. The listedpriority pollutants found in variousdiesel oils can include, benzene, toluene,

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ethylbenzene, naphthalene,phenanthrene, fluorene, and phenol.Diesel oil may contain from 20 to 60percent by volume aromatichydrocarbons. The aromatichydrocarbons, such as benzenes,naphthalenes, and phenanthrenes,constitute the more toxic components ofpetroleum products such as diesel oil.Diesel oil also contains a number ofnonconventional pollutants, includingpolynuclear aromatic hydrocarbonssuch as methylnaphthalene,dimethylnaphthalene,methylphenanthrene, and otheralkylated forms of each of the listedtoxic pollutants.

Because "diesel oil" is neither a listedtoxic pollutant nor a listed conventionalpollutant it is non-conventionalpollutant. The parameter diesel oil isused as an indicator for the toxicorganic pollutants that it is composed ofbecause it would be technologicallyinfeasible to develop effluent limitationsfor all of the individual toxic organicpollutants. The Agency has determinedthat control of these toxic organicpollutants by the regulation of "dieseloil" as proposed represents BAT-level ofcontrol of the toxics of concern.

The proposed regulations would alsolimit the toxicity of discharged drillingfluids with a 96-hour LC50 toxicitylimitation. The LC50 limitation proposedis 3.0 percent by volume of the dilutedsuspended particulate phase, as aminimum (no single analysis to exceed).The analytical method for determiningthe 96-hour LC50 toxicity is a bioassaymethod that was also included in theproposed regulations as an appendix (50FR 34631). The purpose of the LC50limitation is to reduce the levels of toxicconstituents in drilling fluid discharges,including additives such as oil orlubricity agents and some of thenumerous specialty additives that maycontribute significantly to the toxicity ofthe drilling fluids.

The proposed regulations would alsoprohibit the discharge of oil-baseddrilling fluids. This limitation continuesthe effective prohibition on thedischarge of oil-based drilling fluids thatresults from the BPT requirement of "nodischarge of free oil". The oil present insuch fluids would serve as an"indicator" pollutant to control thedischarge of priority pollutantscontained in the oils added to or presentin oil-based drilling fluids at the BATlevel of control. The priority pollutantsthat would be controlled includebenzene, toluene, ethylbenzene andnaphthalene. The Agency hasdetermined that the prohibition on thedischarge of oil-based drilling fluids

would result in BAT-level control for thetoxics of concern in these drillingwastes.

The proposed regulations would alsolimit the amounts of mercury andcadmium that are in discharged drillingfluids. The proposed effluent limitationsfor mercury and cadmium are 1 mg/kgeach, dry weight basis in the wholedrilling fluid, as a maximum limitation(i.e., no single analysis to exceed). Theselimitations would apply to thedischarged drilling fluid. Compliancewith these limitations would likely beaccomplished by control of thesepriority pollutants in the baritecomponent of the drilling fluid.

2. BCT. As stated previously, today'snotice presents information for thepurpose of promulating BAT and NSPSregulations from drilling fluids and drillcuttings. The August 26, 1985, proposaldid include a BCT limitation whichwould prohibit the discharge of free oilin these wastes as measured by thestatic sheen test. The static sheen testmethod was included in the proposedregulations as an appendix (50 FR34627). The pollutant parameter free oilwas proposed to be regulated at the BCTlevel of control. However, with theexception of free oil, BCT requirementsfor drilling fluids were reserved forfuture rulemaking until after thepromulgation of the general BCTmethodology. The general BCTmethodology was subsequentlypromulgated by EPA on July 9, 1986 (51FR 24974]. The Agency intends to issue aseparate Federal Register notice topropose BCT for drilling fluids (and drillcuttings). Subsequently, the Agency willissue final BAT, BCT and NSPSregulations for drilling fluids and drillcuttings.

3. NSPS. The proposed regulationswould establish NSPS limitations forfree oil, oil-based drilling fluids, dieseloil, toxicity, mercury and cadmium asdescribed above for the BAT level ofcontrol.

The proposed regulations includeddefinitions for certain terms used toclassify a "new source" for the offshoresubcategory. These definitions wouldfacilitate the application of the term"new source" to activities covered inthis subcategory, including mobile andfixed exploratory and developmentdrilling operations as well as productionoperations. Refer to the 1985 proposalnotice for a detailed discussion of theAgency's intent in applying the newsource designation. Comments werereceived regarding the proposed newsource definition, but the Agency is notpresenting any changes to the proposeddefinition at this time.

B. Drill Cuttings

1. BAT. The proposed BAT regulationsfor drill cuttings would prohibit thedischarge of free oil as measured by thestatic sheen test. The pollutantparameter free oil was proposed to beregulated as an "indicator" pollutant atthe BAT level for control of thedischarge of priority pollutants in the oilcontained in drill cutttings. Free oil isproposed to be used as an indicatorpollutant for the priority pollutantscontained in the oil because it would betechnologically infeasible to developeffluent limitations for each of theindividual priority pollutants containedin free oil. The priority pollutants thatwould be controlled include benzene,toluene, ethylbenzene and naphthalene.The Agency has determined that theprohibition on the discharge of free oilwould result in BAT-level control for thetoxics of concern in drilling wastes.

In addition, the proposed regulationswould prohibit the discharge of dieseloil in detectable amounts. The pollutantparameter diesel oil was also proposedto be regulated as an "indicator"pollutant at the BAT level for control ofthe discharge of priority pollutants indiesel oil contained in drill cuttings.Diesel oil is proposed to be used as anindicator pollutant for the prioritypollutants contained in diesel oilbecause it would be technologicallyinfeasible to develop effluent limitationsfor all of the individual prioritypollutants. The priority and non-conventional pollutants to be controlledby the use of diesel oil as an indicatorpollutant are the same as that discussedabove for the BAT-level of control fordrilling fluids.

The proposed regulations would alsoprohibit the discharge of drill cuttingscontaining oil-based drilling fluids. Asnoted previously, such fluids wouldserve as "indicator" pollutants tocontrol, at the BAT level, the dischargeof priority pollutants contained in theoils added to or present in oil-baseddrilling fluids and transferred to drillcuttings.

2. BCT. The August 26, 1985 proposedBCT regulations for drill cuttings wouldprohibit the discharge of free oil asmeasured by the static sheen test. Thepollutant parameter free oil wasproposed to be regulated at the BCTlevel for control of the discharge of oilcontained in drill cuttings.

With the exception of free oil, BCTrequirements for drill cuttings werereserved for future rulemaking until afterthe promulgation of the general BCTmethodology. The general BCTmethodology was subsequently

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promulgated by EPA on July 9. 1986 (51FR 24974). The Agency intends topropose BCT in a separate FederalRegister notice for drill cuttings (anddrilling fluids).

3. NSPS. The proposed regulationswould establish NSPS limitations for thedischarge of drill cuttings containingfree oil, drill cuttings associated withoil-based drilling fluids, and drillcuttings that contain diesel oil asdescribed above.

I. New Technical Information Related

To the Proposed BA T/NSPS regulations

A. Drilling Fluid Toxicity Test

The proposed BAT and NSPSregulations would regulate drilling fluidsby specifying a limit on the toxicity ofthe discharged fluid as determinedthrough laboratory testing of samples ofthe fluids. The testing would consist ofexposing test organisms to solutionscontaining different concentrations ofthe fluids. The test results would beused to determine concentration valueslethal to 50% of the test organisms, i.e.,LC5O values. These LC5O values wouldbe used to determine compliance withthe toxicity limitation. The proposedBAT and NSPS regulations contain alimitation on the LC50 of dischargeddrilling fluids of 3.0 percent by volumeof the diluted suspended particulatephase ("SPP basis") of the drilling fluidswastestream.

EPA accounted for variation in drillingfluid toxicity testing during the processof establishing the proposed toxicitylimitation. The Agency proposed alimitation equal to the measured toxicityof the most toxic of the eight genericwater-based drilling fluids. (The eightgeneric drilling fluids are identified inAppendix B of the August 26, 1985proposal; 40 FR 34632.) Test methodvariability and analytical variabilitywere accounted for in the proposedlimitation because they were inherentcomponents of the procedures used bythe Agency in performing the toxicitytesting and subsequent calculations. Noexplicit additional allowances forvariation in the test method (intra- orinter-laboratory variability) or variationin "batches" of discharged wastematerial were used in establishing theproposed toxicity limitation. Moreover,the Agency has not historically providedfor such additional allowances in thedevelopment of effluent limitations.

EPA has received numerouscomments on the proposed toxicitylimitation. In particular, industrycommented that the toxicity limits maybe failed as a result of intra- and inter-laboratory variability in test results.

One existing source of data for use inevaluating inter-laboratory variability isthe study that was performed to aid theAgency in the selection of laboratoriesto conduct toxicity tests for EPA undercontract. This data collection effort waspart of an Agency "invitation for bid"[IFB} contracting process to provideacute toxicity test method performanceinformation by laboratories attemptingto qualify for contract analyticalservices to the Agency.

A detailed description of thestatistical analysis on the IFB data isdescribed in a paper titled "ToxicityTesting of Drilling Fluids: AssessingLaboratory Performance andVariability" (R.C. Bailey, B.P. Eynon),which is available in the record for thisrulemaking. The Bailey-Eynonassessment also evaluates intra-laboratory variability using additionaldata from the EPA Gulf BreezeLaboratory. The American PetroleumInstitute (API) has criticized the Bailey-Eynon assessment in a paper titled"Variability in Drilling Fluid ToxicityTests" (J.E. O'Reilly, L.R. LaMotte). Thispaper also is included in the rulemakingrecord.

In order to draw final conclusionsconcerning variability of toxicity testresults, the Agency is currentlyconducting a further evaluation of thedrilling fluid toxicity test. This study willestimate intra- and inter-laboratoryvariability in the test results. It will alsoassess differences in intra- and inter-laboratory variation of estimatedtoxicity between a drilling mud and thatsame batch of drilling mud with oiladded. The study will require eachlaboratory to conduct individual range-finding tests and to calculate LC50's. Anintra-laboratory variability analysis-willbe based upon data from laboratorieswith levels of experience ranging fromsome experience to highly experienced.The study will not include estimates ofvariability resulting from repeatedmeasurements on different "batches" ofthe same mud since this information isnot needed to evaluate the drilling fluidtoxicity test.

B. Discharge of Oil in Water-BasedDrilling Fluids

Water-based drilling fluids used inoffshore drilling operations sometimeshave oil, either diesel oil or mineral oil,added to them. Drilling fluids may alsocontain entained formationhydrocarbons. (The discharge of oil-based drilling fluids would be prohibitedunder the proposed regulation).

Oil can be used to improve thelubricating properties of a water-basedmud system and as an aid in freeing drillpipe that has become stuck downhole

during the drilling operation. Althoughdiesel oil is often the most readilyavailable oil at a drilling site, mineraloils have had a great deal of userecently for these purposes. When oil isused an an aid in freeing stuck drill pipe,.a standard technique is to pump a slugor "pill" of oil or oil-based fluid downthe drill string and "spot" it in theannulus area where the pipe is stuck.After use, the pill may be removed fromthe bulk mud system and disposed ofseparately. Even if the pill is recovered,residual oil from the pill can mix withthe remainder of the mud system.

In recent years, research sponsored byboth industry and government hasshown that the presence of petroleumhydrocarbons in drilling fluidcontributes significantly to its toxicidy.Diesel oil is a complex mixture ofpetroleum hydrocarbons. It is known tobe highly toxic to marine organisms andto contain toxic and nonconventionalpollutants. There is evidence that dieseloil contributes significantly to thetoxicity of drilling fluids that contain it.Toxicity data collected to date haveshown that water-based mudscontaining diesel oil are substantiallymore toxic than muds without diesel.Mineral oil, which is available to servethe same operational requirements asdiesel oil, has been shown to be a lesstoxic alternative to diesel oil. As aresult, EPA has proposed a prohibitionon the discharge of water-based drillingmuds containing diesel oil and hasencouraged the substitution of mineraloil for diesel oil

The use of mineral oil instead ofdiesel oil as an additive in Water-baseddrilling fluids will reduce the quantity oftoxic and nonconventional organicpollutants that are present in a drillingfluid, as compared to the quantity ofthese pollutants present when usingdiesel oil as an additive. Mineral oils,with their lower aromatic hydrocarboncontent and lower toxicity, contain,lower concentrations of toxic pollutantsthan do diesel oils.

The proposed regulations wouldprohibit the discharge of diesel oil indetectable amounts in drilling fluidwaste streams. The Agency selected thepollutant "diesel oil" as an "indicator"of the listed toxic pollutants present indiesel oil that are controlled throughcompliance with the effluent limitation,i.e., no discharge. The technology basisfor this limitation is product substitutionof less toxic mineral oil for diesel oil.

As discussed in the preamble to theproposed regulations, the reason forprohibiting diesel discharges is toreduce the discharge of priority toxicand nonconventional organic pollutants

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known to be present in diesel oils. Thetypes and levels of these pollutantspresent in diesel oils have recently beendocumented in a study sponsored by theOffshore Operators Committee OOC).The laboratory study was conducted toexamine the chemical characteristics ofselected diesel and mineral oils. Thefindings are presented in twocomprehensive reports prepared byBattelle New England Marine ResearchLaboratory. These studies were madeavailable to the Agency by the industryand are available in the rulemakingrecord.

Some typical methods for compliancewith the diesel oil limitation are: (1) Useof product substitutes such as lowtoxicity mineral oils for spotting andlubricity purposes; and (2) use of dieseloil for spotting and/or lubricity purposesand transporting the used mud system toshore for proper treatment, disposal orreuse.

The industry commenters on theproposed regulations argued that dieseloil is the most effective agent for use inspotting fluids and that the use anddischarge of diesel oil for this purposeshould be allowed by the regulations.The industry attempted to demonstratethis preference for diesel oil in spottingfluids by providing EPA with the resultsof the industry-sponsored surveysdiscussed below. The industry alsoproposed to EPA that a program oflimited duration be undertaken todetermine the efficiency of recovering adiesel pill so that the discharge of dieseloil would be minimized, if noteliminated, when the used mud systemis discharged to the ocean.

1. American Petroleum InstituteDrilling Fluids Survey. In 1984 theAmerican Petroleum Institute (API)conducted a survey among sixteenoffshore oil operators in the Guld ofMexico to obtain information on the useof diesel and mineral oils in water-based drilling fluids for the year 1983.Because the number of mineral oilapplications in 1983 was small, APIconducted a limited additional survey toobtain more data on experience withmineral oil pills in 1984.

These survey data presented by APIindicate that mineral oil is morecommonly used as a lubricant, whilediesel oil is more commonly used forspotting purposes. Hydrocarbons (dieselor mineral oil) were added for lubricityto 12% of the 548 wells included in thesurvey. For 8% of the wells (44 wells),mineral oil was added, while for 4% ofthe wells (21 wells), diesel oil wasadded. For those drilling muds to whichlubricity hydorcarbon was added,typically 3 percent (by volume) of the

mud formulation was composed ofhydrocarbon additive.

2. Offshore Operators CommitteeSpotting Fluid Survey. Most industryrepresentatives consider mineral oil tobe adequate for use as a lubricity agentbut believe diesel oil to be a superiormaterials for freeing stuck pipe. Insupport of this position, industry hasprovided the Agency with the results ofa retrospective survey comparing thesuccess rates of diesel oil and mineraloil in freeing stuck pipe. This projectwas conducted in 1986 by the OffshoreOperator's Committee (OO) andcovered the years 1983 to 1986.

The study examined information from2,287 wells drilled in the Gulf of Mexicoduring that time period. Survey formswere distributed to operators who wereasked to specify-the number of wellsdrilled with water-based mud for eachyear covered by the survey and tosupply certain information on each stuckpipe event where an oil-based spottingfluid was used. The API survey formasked for the data ihe event took place,the time interval between sticking andspotting activities, the depth at whichthe stuck pipe incident occurred, thebased oil used in the spotting fluid,whether the hole was straight ordirectional, and whether the pill wassuccessful in freeing the pipe.

Participants included twelve major oilcompanies and accounted for more thanhalf of the offshore wells drilled duringthis period. Since some of thesecompanies have more than oneoperating division, a total of sixteensurvey response were received.

Of 2,287 wells surveyed that weredrilled with water-based mud, 506 stuckpipe incidents were identified in whichthe operator chose to use an oil additiveto attempt to free stuck pipe. Diesel oilpills were reportedly successful 52.7% ofthe time and mineral oil pills weresuccessful 32.7% of the time in freeingstuck pipe, as shown in the followingtable:

OOC SPOTTING FLUID SURVEY RESULTS

Number Number SuccessSpotting fluid incidents incidents rate

fluid used l (percent)

Diesel .................. 298 157 52.7Mineral ................ 208 68 32.7

Numerous other factors could impactthe success of a pill in addition to thebase oil. For example, Love (1983)determined that the chance of freeingstuck pipe in 113 documented cases andthe potential success of such operationswere related to specific conditions at

each well. Success decreased withincreasing well angle, mud weight,amount of open hole, API fluid loss ofthe mud, and bottom-hole-assemblylength. The chances of success droppedoff substantially when a numeric indexcalculated from the above factorsexceeded a certain level.

In addition to the above factors, Lovefound that pill additive packages (e.g.,surfactants, emulsifiers, etc.),rheological properties of the mud, timeuntil spotting, site-specific geologicalcharacteristics, and operator experiencewere likely to affect the success of aspotting operation.

The OOC examined four of thesefactors in their study: base oil, time untilspotting, depth of spot, and type of well(straight or deviated). Results indicatedthat reducing the length of time until thespot was applied improved the chanceof success dramatically for diesel pills.A similar but apparently less dramatictrend was observed for mineral oil pills.The diesel oil success rate was 61% ifthe pill was spotted in less than 5 hours.The rate dropped of 41% if the spottingtime until spot exceeded 10 hours. Themineral oil success rate was 35% if thepill was spotting in less than 5 hours; therate dropped.to 31% if the time until thespot exceeded 10 hours.

Other factors examined by OOCappeared to have less impact on successfor freeing stuck drill pipe. Both dieseland mineral oil showed higher successrates in straight rather than indirectional or deviated wells, with dieseloil maintaining its reported edge overmineral oil by about the samepercentage in each type of well. Notrend was observed between depth ofspot and success rates for diesel ormineral oil pills.

The OOC survey data showed thatsuccess rate with mineral oil pills variedconsiderably among operators. The dataseemed to indicate that greaterexperience with mineral oil usage leadsto considerably higher success ratesthan the reported average. The fiveoperators that reported using mineral oilpills for more than 90% of their stuckpipe incidents experienced an average42% success rate with such pills.

Some of the operators with greatermineral pill usage rates achievedextremely high success rates, whichwere comparable to the highest dieselpill success rates. The three highestsuccess rates among operators usingmineral pills were 58%, 60%, 75%. Thethree highest success rates amongoperators using diesel pills were 60%,60%, and 64%.

Despite the industry's claim thatdiesel pills are more effective than

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mineral pills, the study did show thatmineral oil was used by operators in41% of the stuck pipe incidents. Of the506 incidents in the OOC study, 298 (or59%) were treated with a diesel pill,while 208 (41%) were treated with amineral pill. For some operators, mineraloil was the material of choice. Threeoperators (out of 16) used mineral pillsexclusively. The Agency concludes thatduring the period of this study: (1)Mineral oil was in common use byoperators in the Gulf of Mexico; (2)mineral oil is an available alternative tothe use of diesel oil; and (3) successrates comparable to those with diesel oilcan be achieved with mineral oil.

3. EPA/API Diesel Pill MonitoringProgram (DPMP). In response to theproposed prohibition on the discharge ofdiesel oil, the industry requested thatthe discharge of diesel oil be allowedwhen diesel oil is the residual oil left inthe bulk mud system following the useof a diesel pill and subsequent pillrecovery techniques. Since neither theindustry nor the Agency had sufficientinformation on the effectiveness of pillrecovery, the Agency decided toparticipate with the industry in a testprogram to determine whether diesel oilcan be effectively removed from a mudsystem after use of diesel-based pills.

In an effort to evaluate theeffectiveness of diesel pill recoverytechniques and to gather information onthe extent to which any residual dieseloil contaminates the bulk mud system,EPA's Industrial Technology Division,EPA Regions IV and VI, and EPA'sEnvironmental Research Laboratory inGulf Breeze, FL conducted the Diesel PillMonitoring Program (DPMP) incooperation with the API. The programinvolved the collection and analysis ofsamples from active mud systems priorto use and after recovery of a diesel oilbased pil.

a. DPMP Objectives. The objectives ofthe DPMP were to evaluate theefficiency of diesel pill recovery and todetermine the effectiveness of therecovery practice by measuring thetoxicity and diesel content of the mudsystem before and after pill recovery.

The major parameters used toestablish the efficiency of diesel oilrecovery included the toxicity and dieselcontent of muds both before and after apill is spotted, the volume of materialadded and removed from the mudsystem (recovered pill and buffermaterial), the location and type of wellbeing drilled, and the type and -rheological properties of the mud andpill being used. This information was tobe analyzed and used to determine theefficiency of diesel recovery and the

acceptability of the remainder of themud system for discharge.

b. Program Description. The DPMPrequired an operator who used a dieselpill and intended to discharge thedrilling muds to recover the diesel pillplus at least 50 barrels of mud thatsurfaced from downhole both before andafter the pill, or as much as necessaryuntil no visible oil was detected. Therecovered pill and buffer material couldnot be discharged and had to betransported to shore for either disposalor reuse.

The federal waters of the Gulf ofMexico were chosen for this studybecause of the large number anddiversity of drilling operations. TheDPMP was implemented as part of theAgency's general NPDES permit for oiland gas operations in the Gulf of Mexico(Permit No. GMG 280000). The permit,which was published by EPA Regions IVand VI in the Federal Register on July 9,1986 (51 FR 24897), prohibited thedischarge of water-based drilling mudscontaining diesel oil unless: (1) Thediesel oil was added only for thepurpose of attempting to free stuck pipe,(2) the diesel pill and contaminated mud(buffer) were recovered and notdischarged, and (3) the permitteeparticipated in and complied with thewritten instructions of the DPMP. Theprogram officially started in July 1986with the issuance of the general permit,but some operators began participatingin November 1985. The program endedas part of the permit requirement onSeptember 30, 1987.

Some permittees elected not toparticipate in the DPMP on a well-by-well basis. If a permittee used a dieselpill and did not participate in theprogram, then all waste mud andcuttings generated after introduction ofthe pill were to be transported to shorefor disposal, as required by the generalpermit. If permittees used a mineral oilor non-hydrocarbon based pill insteadof diesel oil to free stuck pipe, then theywere allowed to discharge waste mudand cuttings without participating in theDPMP, provided that all other permitconditions (e.g., toxicity limitation, nodischarge of free oil) were met.

For those operators that didparticipate in the program, the DPMPestablished conditions for pill recovery,toxicity and chemical testing, andmonitoring to generate data on theeffectiveness of current recoverytechniques. DPMP participants wererequired to meet all permit limitationswith the exception of the prohibition onthe discharge of diesel oil. Discharge ofmud containing diesel oil was allowed ifused only for freeing stuck pipe and if

provisions of the DPMP were followed.Also, for permit purposes, compliancewith the toxicity limitation wasdemonstrated by sampling the mud justprior to the introduction of the pill. Theend-of-well toxicity test was alsoconducted, but was used by EPA forinformation only, and not to determinecompliance with the permit.

The procedures for conducting thesampling and analysis program aredocumented in a program manual thatcontains detailed instructions for allparticipants. The program manual isincluded in the record for thisrulemaking.

The DPMP was managed by anOversight Committee with membersrepresenting EPA's IndustrialTechnology Division and RegionalOffices, EPA's Environmental ResearchLaboratory, the Natural ResourcesDefense Council, and API's Committeeon Environmental Conservation. TheOversight Committee carried out theplanning and development of the DPMP,met periodically to review laboratoryactivities and the information beinggathered and analyses being performed,monitor the progress of theinvestigations, amend certain pillrecovery techniques and sampling/analytical procedures, and issue a finalreport on the findings and conclusion ofthe DPMP.

EPA's Environmental ReserachLaboratory, Office of Research andDevelopment, in Gulf Breeze, FL actedas the quality review laboratory for thetoxicity testing part of this program. TheGulf Breeze Lab has been conductingresearch activities since 1976 to evaluatethe potential impact of drilling fluids onthe marine environment. The lab isexperienced in handling and testingdrilling fluid samples, and was involvedin developing the protocol for theproposed Drilling Fluids Toxicity Testmethod (50 FR 34631). Thus, the GulfBreeze Lab reviewed toxicity analysesgenerated during the DPMP, advised ondata quality, and conducted analyses onduplicate samples.

The participating drilling operatorswere required to conduct samplingactivities with prepackaged samplingkits whenever a diesel pill was used tofree stuck pipe. Samples were taken ofthe pill, the diesel oil used to formulatethe pill, and the active mud systembefore spotting and after the pill wasrecovered. Samples were shipped to adesignated Central Control Laboratory(CCL) which was responsible formanaging the flow of samples, analyses,and information. The CCL monitored theperformance of contract laboratoriesand transmitted results to permittees

41362 Federal Register / Vol. 53, No. 204 / Friday, October 21, 1988 / Proposed Rules41362



and to EPA's Sample Control Center(SCC).

The SCC is an Agency contractor thatassists the Industrial TechnologyDivision with the tracking of samples,assignment and performance evaluationof analytical laboratories, and thecompilation of analytical results forDivision projects. Thus, the SCC wasassigned the task of monitoring thestatus of the DPMP for the Agency. TheSCC was also responsible formaintaining a computerized datamanagement system for all analyticalinformation gathered during thisprogram for Agency access andrecordkeeping purposes, and forpreparing quarterly data compilations tothe Oversight Committee.

c. Diesel Pill Monitoring ProgramFindngs. The Agency has performedanalyses of the diesel pill programinformation received to date, Thisencompasses information on 119 stuckpipe incidents that occurred fromNovember 1985 through September 1987.The Agency focused on analyses thatwould indicate the amount of diesel oilrecovered (i.e., removed from the bulkdrilling fluid system) based upon knownamounts introduced with the diesel pillformulation.

The Agency first examined theamount of diesel oil remaining in thebulk mud system after pill recovery andits relationship to the size of the bufferthat was removed with the pill.According to the design of the pillrecovery technique, it was expected thatan increase in buffer size would result inhigher diesel recover (i.e., loweramounts of diesel oil remaining in thebulk mud system).

Diesel oil recovery was determined asthe difference between the amount ofdiesel oil reportedly added to the mudsystem and the amount measured in theactive system after two completerevolutions of the mud system followingpill recovery. The results of the analysesindicate that, for the time period afterthe general NPDES permit for the Gulf ofMexico became effective in July 1986,the median diesel oil recovery level wasabout 80 percent. The amount of dieseloil remaining in the bulk mud systemsranged from less than one percent tomore than 95 percent of the volumeadded, with a median level of almost 20percent.

The amount of diesel oil remaining inthe system did not appear to correlatewith buffer size. Increasing the amountof buffer material collected had littleeffect on the median recovery level.

Next, the Agency evaluated DPMPdata to determine if there werecorrelations between measured dieseloil content and the acute toxicity (LC50)

of drilling fluids. The Agency found thata distinct and rather dramaticrelationship does exist. At low dieselconcentrations, acute toxicity was foundto increase rapidly with increasingdiesel content. The data clearly supportprevious findings that diesel oil is amajor contributor to mud toxicity. Thefinding that the acute toxicity of drillingfluids is heavily influenced by theamount of diesel oil present supports theAgency's original proposal to prohibitthe discharge of diesel oil in drillingwastes.

The success rates for freeing stuckpipe for the DPMP and the OOCSpotting Fluid Survey (see previousdiscussion) were compared. The dieselpill success rate from the DPMP wasfound to be 36 percent. This value wasderived by considering all stuck pipeincidents that occurred during theDPMP, which included multiple pills forsome sticking incidents and multiplesticking incidents for some wells. Theindustry analysis of the OOC surveydata included consideration of multiplestuck pipe incidents per well but successrates were calculated by consideringonly the first pill per sticking incident.

The Agency recalcuated the diesel pillsuccess rate from the DPMP on the samebasis used by OOC in its survey. Theresultant value is only a 40 percentdiesel oil success rate, compared to thereported 52.7 percent diesel oil successrate from the OOC survey. It is not clearwhy the reported diesel pill successrates differ between these two studies.The DPMP data cast doubt upon theindustry position regarding superiorityof diesel oil over mineral oil in freeingstuck pipe.

It should be noted that during thecourse of the DPMP the use of mineraloil pills for freeing stuck pipe in the Gulfof Mexico reportedly declined. Industryhas stated that the DPMP became adistincentive for the use and furtherdevelopment of mineral oil pills.However, industry representatives havenoted that onsite recovery techniqueswould be essentially the same for pillsformulated with either diesel or mineraloil.

Total costs for operators participatingin the DPMP and transporting anddisposing of the pill and buffer materialonshore were reported to average about$11,000 per spotting episode. Of thattotal, the costs of transporting therecovered pill and buffer from the rig tothe disposal site, cleaning tanks, andlandfilling the waste material averagedapproximately $8,000 per episode.

d. Conclusions on the Diesel PillMonitoring Program. Based on analysesto date of information generated duringthe DPMP, the Agency believes that use

of the pill recovery techniquesimplemented during the program doesnot result in recovery of sufficientamounts of the diesel pill and reductionof mud toxicity to acceptable levels fordischarge of bulk mud systems. Mudsystems for approximately one-half ofall wells in the DPMP contained residualdiesel levels between one and fivepercent by weight after introduction of adiesel pill and subsequent pill recoveryefforts. In addition, mud systems forapproximately 80 percent of the DPMPwells failed the proposed 30,000 ppmLC50 limitation after pill recovery.Almost half that number (40 percent ofthe total) of the DPMP wells had water-based mud systems that containedresidual diesel following pill recoveryand showed LC50 values of less than(more toxic than) 5,000 ppm.

4. Conclusion on the Discharge ofDiesel Oil. For the reasons discussedabove, the Agency believes that itsproposed prohibition on the discharge ofdiesel oil in detectable amounts isappropriate for the BAT and NSPSlevels of.control. The technology basisfor the prohibition on the discharge ofdetectable amounts of diesel oil indrilling fluids and drill cuttings issubstitution of mineral oil for diesel oiland lubricity and spotting purposes.Alternatively, where offshore operatorschoose to use diesel oil in a mud system,many opeators have the option totransport used mud systems andassociated cuttings to shore for propertreatment or disposal.

'In comments submitted to the Agencyon the August 26, 1985 proposedregulations, the American PetroleumInstitute stated its agreement with EPAthat satisfactory mineral oil substitutesare available for general mud lubricityapplications, and that use of diesel oilfor this purpose should be discontinued.API also maintained that, for use as aspotting fluid to free stuck drill pipe,mineral oil substitutes are not aseffective as diesel in all cases. However,results of the surveys presented in thisnotice indicate that mineral oil additivesare available, are being used by offshoreoperators, and are capable of being aseffective as diesel in spotting fluidapplications.

The Agency solicits comments on allaspects of this discussion and thestudies used by the Agency toreconsider the proposed dieseldischarge prohibition. The Agency alsosolicits any additional relevant data onthis issue. The Agency will considerthese data in the formulation of the finaleffluent limitations and standards fordrilling fluids and drill cuttings.

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C. Analytical Method for Diesel OilDetection

The August 26, 1985 Federal Registernotice proposed a method for detectingthe presence of diesel oil in drillingfluids and drill cuttings waste streams.The method, based on retort distillationand gas chromatography, hassubsequently been modified based onexperience gained during the conduct ofthe Diesel Pill Monitoring Program. Thecurrent version of Proposed Method1651, "Oil Content and Diesel Oil inDrilling Muds and Drill Cuttings byRetort Gravimetry and GCFID" ispresented in Appendix A of this noticefor review and comment.

This method for determining theidentity and concentration of diesel oilin drilling wastes has an estimateddetection limit of 100 mg/kg. Data on theprecision and accuracy of the methodhave been generated and are included inthe record for this rulemaking.

Today's modified version of the dieselanalytical method also includes aproposed method for determining the oilcontent of drilling wastes. Discussion onthe Agency's intended use of oil contentdeterminations is presented in Part 2 oftoday's notice.

D. Metals LimitationsThe proposed BAT and NSPS

regulations would limit the levels ofmercury and cadmium that could bepresent in discharged drilling fluids. Theprimary source of these toxic metals isthe barite component of drilling fluids.The August 26, 1985 proposal includedproposed effluent limitations of I mg/kgeach of mercury and cadmium in thewhole drilling fluid on a dry weightbasis. The proposed effluent limitationswould be maximum values (no singleanalysis to exceed).

Upon review and consideration of thecomments and additional informationreceived on this aspect of the proposedregulations, the Agency is consideringdifferent BAT and NSPS effluentlimitations for control of mercury andcadmium levels in drilling fluids. Thelimitations being considered are 1.5 mg/kg of mercury and 2.5 mg/kg of cadmiumin the whole drilling fluid on a dryweight basis, These effluent limitationsalso would be maximum (no singlesample to exceed) values.

At proposal, the Agency estimatedthat mercury and cadmium limitations of1 mg/kg each would result in a priceincrease of about 15% for barite.Industry commenters argued that theproposed mercury and cadmiumlimitations would result in a 65%increase in the price of barite that,contains mercury and cadmium at

sufficiently low levels to allow forcompliance with the effluent limitations.The price increase would be due toincreased demand for such "clean"barite and additional costs insegregating and transporting supplies ofclean barite for offshore use. It wassuggested that there also may be aquestion about adequate sources andstocks of such "clean" barite for use inoffshore drilling. Industry commentersindicated that sufficient supplies ofbarite containing no more than 3 mg/kgmercury and 5 mg/kg cadmium areavailable for offshore use. The Agency'sanalysis of industry-supplied dataindicates that there should be no priceincrease for barite if barite containingmercury and cadmium at levels nohigher than 3 mg/kg and 5 mg/kg,respectively, could be used to formulatedrilling fluids.

The 1.5 mg/kg mercury and 2.5 mg/kgcadmium effluent limitations beingconsidered by the Agency are end ofpipe limitations based upon the use indrilling fluids of: (1) Barite containing nomore than 3 mg/kg mercury and 5 mg/kgcadmium and (2) a typical barite contentin drilling fluid of 50% barite by weight.If the barite content in the whole drillingfluid is 50%, the concentration of eachmetal in the whole drilling fluid wouldbe about one-half of its concentration inthe stock barite.

The Agency may establish the finalBAT and NSPS effluent limitations equalto 1 mg/kg each of mercury andcadmium in the whole drilling fluid orequal to 1.5 mg/kg of mercury and 2.5mg/kg of cadmium in the whole drillingfluid. The Agency may also establish thelimitations at levels in the whole drillingfluid that the Agency determines moreaccurately reflect the use of baritecontaining no more than 3 mg/kg ofmercury and 5 mg/kg of cadmium. TheAgency believes that either set ofeffluent limitations under considerationfor mercury and cadmium in wholedrilling fluid is potentially appropriatefor the BAT and NSPS levels of controland that either set of limitations iseconomically achievable.

The Agency solicits comment on allaspects of the mercury and cadmiumlimitations discussed here. In particular,the Agency solicits: (1) Data relating tothe availability of adequate supplies ofbarite which will provide for compliancewith particular metals limitations indischarged drilling fluids; (2)information about the appropriatenessof its tentative conclusion that the use indrilling fluids of barite containing nomore than 3 mg/kg mercury of 5 mg/kgcadmium correlates properly with end ofpipe limitations of 1.5 mg/kg for mercuryand 2.5 mg/kg for cadmium at the BAT

and NSPS levels of control (this includesdata on the amounts and proportions ofthe barite component used in actualdrilling fluid formulations, theproportion of drilling fluid systems andvolumes of actual drilling fluids thatcontain barite in greater or lesserproportions than the estimate of 50% byweight that was used for the Agency'sanalysis, and data that would aid in theassessment of the changing proportionof the barite component of drilling fluidsystems as the drilling fluid compositionis modified during the drilling of a well);and (3) data that would aid in discerningdifferences in environmental effectsbetween the effluent limitations underconsideration.

III. Changes to Costing Data andAssumptions for Estimates of EconomicImpacts

The Agency has re-costed compliancewith the proposed regulatory option fordrilling fluids and drill cuttings basedupon additional technical and costinformation provided in comments onthe proposed regulation and additionalinformation collected by the Agencysince proposal. The Agency selected theyear 1986 as the basis for presentationof the regulatory costs and economicanalysis discussed in this noticebecause 1986 is the latest year for whichsufficient actual costs and economicdata are available.

The following discussion summarizesthe major and most of the minor changesto costing items and assumptions usedin developing aggregate industrycompliance costs. The revisedcompliance costs were then used toperform a revised economic impactanalysis of the amended regulatoryapproach presented in this section. Therevised economic impact analysis isincluded in the rulemaking record. Asummary of the economic impactanalysis is presented in Section IV ofthis pa'rt of today's notice. The Agencysolicits comment on these changes to thecosting data and assumptions and onthe revised economic impact analysis.

A. Toxicity Failure Rate for Water-Based Drilling Fluids

The Agency has undertaken ananalysis of data on water-based drillingfluids collected by both EPA and theindustry over the past two years toestimate failure rates of the proposedtoxicity limitation (30,000 ppm,suspended particulate phase basis) inorder to better estimate the aggregateindustry compliance costs of theproposed regulatory option. These datainclude measured oil content and acutetoxicity of field (used) muds.



The Agency has categorized theinformation by "data set". The data setsare identified as follows: The first dataset is field mud data collected by APIand presented to EPA in comments onthe August 26, 1985 proposed regulations("API 1"). The second data set is anextension of data collection by APIsubsequent to API'l and submitted tothe Agency in October 1986 ("API 2").The third data set includes mudproperties data, well identificationinformation, and analytical results forfield muds collected during the DieselPill Monitoring Program ("DPMP") fromNovember 1985 through September 1987.The fourth data set is field mudinformation generated by the industryand submitted to EPA Region VI for thealternative toxicity request ("ATR")program under the NPDES permit foroiland gas operations in federal waters ofthe Gulf of Mexico (Permit No. GMG280000). The fifth set of data is dischargemonitoring report ("DMR") data that arebeing provided to EPA Region VI by theindustry under the terms of the NPDESgeneral permit for oil and gas operationsin federal waters of the Gulf of Mexico.

Mud data were grouped to representthree segments of the total population ofwells employing water-based mudsystems. The segments included mudsystems with no added oil, oil added forlubricity, and oil added for spottingpurposes. Expected failure rates at theproposed LC50 limitation of 30,000 ppmwere estimated for each of the threesegments and thus for the total wellpopulation. Compliance costs were thenestimated based on product substitutionand transport of muds to shore fordisposal.

Depending upon the individual datasets or combinations of data sets used toestimate toxicity failure rates basedupon measured oil content, the toxicityfailure rate for water-based drillingfluids which contain no added oil(original formulation, no reportedlubricity or spotting fluids) range fromapproximately 2% to 15%. That is,between 2% and 15% of those water-based drilling fluid systems that do notcontain added oil may be expected tofail the proposed toxicity limitation of30,000 ppm SPP. If the toxicity failurerate were closer to 15% than to 2%, theindustry would incur considerablyhigher costs for compliance with thetoxicity limitation than the Agency hadoriginally estimated. This factor, inconjunction with certain other costingelements discussed below, can addsignificantly to the aggregate industrycompliance cost for the proposedeffluent limitations.

The majority of water-based drillingfluid systems used in the Gulf of Mexicodo not contain added oil. Results of theAPI Drilling Fluid Survey and the OOCSpotting Fluid Survey discussedpreviously support this conclusion.Reportedly, 88% of wells using water-based muds do not use oil for lubricity(API, 1983 data). Similarly, 78% of suchwells do not use oil for spottingpurposes (API, 1983-86 data). Therefore,assuming that the number of new wellsthat will not use oil for lubricity orspotting purposes will be uniformlydistributed, a minimum of 69%(88% X 78%) of all water-based drillingfluid systems will contain no added oil.Assuming 978 new offshore wells aredrilled each year (see "Annual Rate ofDevelopment", below), between 13 wells(2% X 69% X 978) and 101 wells(15% X 69% X 978) drilled each yearusing water-based muds with no addedoil may fail the proposed 30,000 ppmSPP toxicity limitation. Thus, as shownon Table 2 in Section IV of this part, theestimated annual industry cost ofcomplying with only the proposedtoxicity limitation of 30,000 ppm SPPvaries from $22 million to $48 million(1986 dollars) depending on theestimated toxicity failure rate of waterbased muds to which no oil has beenadded.

B. Annual Rate of Development

The costing and economic analysesfor the proposed regulation.were basedupon an annual average of 1166 offshorewells drilled per year through the year2000. The revised costing and economicsare based upon an annual average of978 wells drilled per year through theyear 2000. The revised estimate is basedupon updated projections of offshore oiland gas activity developed by theDepartment of Interior's MineralsManagement Service (MMS). MMS haspublished 30-year forecasts of OuterContinental Shelf oil and gas productionfor major regions: the Atlantic, Gulf ofMexico, Pacific, and Alaska. Theseprojections improve upon theDepartment of Energy/EnergyAdministration forecasts used by EPA atproposal for reasons outlined in SectionIV of this part of today's notice.

C. Model Well CharacteristicsModel well characteristics were

established for the purpose of estimatingcompliance costs for the regulatoryapproaches under consideration. Theassumed characteristics of a model10,000 foot well in the Gulf of Mexicoare discussed in Part 2 of this notice andare summarized below.

Drilling a typical 10,000 foot well isassumed to take 35 calendar days with

20 days of actual drilling time. Thevolumes of drilling fluid and drillcuttings discharges from a 10,000 footmodel well are estimated to be 6,749 and1,430 barrels, respectively. Water-baseddrilling fluids with oil added for lubricityplus spotting purposes are assumed tocontain 5% oil by volume. Untreateddrill cuttings associated with oil-baseddrilling fluids are assumed to contain20% oil by weight. Drill cuttingsassociated with water-based drillingfluids to which oil has been added areassumed to contain 1% oil by weight.

There are two major refinements tothe model well characteristics used forevaluating the proposed regulation andthose used for the revised estimatespresented in today's notice. They are: (1)An additional bulk mud discharge of1,400 barrels to account for the activemud system at the end of a drillingcampaign; and (2) an assumption of 1%instead of 10% oil content (weight basis)in cuttings associated with the use ofwater-based muds to which oil has beenadded.

D. Transportation and Disposal

For drilling wastes that do not complywith the proposed effluent limitations,the method of disposal at proposal andnow is assumed to be transport of thewastes to shore by vessel forreconditioning and reuse (oil muds) orland disposal (cuttings and water-basedmuds). Model cost scenarios fortransport and disposal were based oninformation provided by industrysources, as presented in Part 2 of thisnotice. These costs include rental ofsupply boats at $3,000 per day, andrevised costs for material containers,labor for loading, and unloading,transport, and landfill disposal at $6.50per barrel of mud and $6.00 per barrel ofcuttings.

The number or proportion of allwater-based drilling fluid systems andassociated cuttings that would have tobe disposed of in this manner wasreestimated. The estimate used for theproposed regulation was that 10% of allmuds and cuttings would have to betransported to shore for disposal due tofailure of one or more of the proposedeffluent limitations. Revised estimatesrange up to 23% of all water-based mudsand about 3% of all associated cuttingsbeing transported to shore for disposal.(For oil-based muds and associatedcuttings, there is no change from the1985 proposed requirement that all suchwastes would have to be transported toshore for disposal.)

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E. Use of Oil-Based and Water-BasedDrilling Fluids

The original and revised costingapproaches assume the use of a water-based mud system in all wells down tothe 10,000 foot model well depth. Oil-based muds may be used for the moredifficult drilling situations (e.g., deviatedholes at greater depths) to improvelubricity, thereby reducing torque andincreasing the rate of penetration, toimprove temperature stability of themud system, and to reduce the chancesof stuck drill pipe. Oil-based muds arealso used in specific geologies like shaleto preclude distortion of the formationstrata that could occur through theabsorption of water from water-basedmuds. API data for 1984 indicate that theaverage depth of all wells drilled deeperthan the model well was 14,000 feet. Itwas assumed for recosting purposes thatoil-based muds would be used below10,000 feet. Of all the wells accountedfor in the 1984 API data base, 30.8%were deeper than 10,000 feet and wereassumed to have used oil-based muds atthe depth interval 10,000 to 14,000 feet.

F. Cost Differential Between Diesel andMineral Oils

The cost of substituting mineral oil fordiesel oil was established at the time ofthe proposed regulation at $2.10 pergallon. This differential cost includedthe increase in delivered purchase priceof the mineral oil over diesel oil and thecosts to provide and maintain separateonsite storage facilities for the mineraloil. Revised estimates presented in

today's notice include a differential costof $2.00 per gallon for calculationsinvolving mineral oil substitution.

G. Pollutant Reduction EstimatesThe issue of pollutant reduction does

not directly affect the aggregate costingof the amended regulatory approach.However, pollutant reduction estimatesare used in determining benefits and areused in evaluating the cost-effectivenessof the various regulatory options. Therevised analysis presented in this partincorporates estimates of the reductionsof specific pollutants (identified below)that would be achieved for each of thecandidate regulatory approachespresented in this part of today's notice.

Determinations of the prioritypollutant organics and nonconventionalorganics content of diesel oil andmineral oil mud additives were made inlaboratory research sponsored by theindustry. These data were used by theAgency to estimate potential reductionsin the direct discharge of benzene,naphthalene, fluorene, phenanthrene,phenol and their alkylated homologues.Discharge reduction estimates were alsomade for mercury, cadmium, and severalother metallic priority pollutants foundin drilling fluids and associated drillcuttings.

H. Failure Rate for "No Discharge ofFree Oil" Limitation (Static Sheen Test)

The approach followed by the Agencyto re-cost compliance with the proposedregulation included consideration ofexpected failure rates for the staticsheen test. As previously noted, the total

population of wells employing water-based mud systems were grouped intothree classes: muds with no added oil,muds with oil added for lubricity, andmuds with oil added for spottingpurposes. The percentage of wells withdischarges that would be likely tocomply with the "no discharge of freeoil" limitation based on the static sheentest were estimated for each of the threeclasses considered. Compliance costswere then determined based ontransporting the wastes to shore for landdisposal.

I. Monitoring Costs

The cost of monitoring for compliancewith effluent limitations is considered tobe an element of the total costs ofcompliance with thexegulation. Thepreamble to the proposed regulationscontained a "suggested" or "typical"monitoring frequency and analyticalcost for each pollutant and waste streamsubject to the regulation for a facilitywhere both development and productionoperations are being performed. Assuch, the total monitoring costspresented were considered to beconservatively high.

Changes were made to the monitoringfrequencies and analytical costspresented in the August 26, 1985proposal for the muds and cuttingswaste streams. These changes involvedthe monitoring frequency of the staticsheen test and the addition of the dieseldetection analysis. A summary ofsuggested sampling frequencies andestimated self-monitoring costs for mudsand cuttings on a per well basis follows:

SUGGESTED SELF-MONITORING FREQUENCIES AND ESTIMATED ANALYTICAL COSTS

Cost per Suggestedsample for Sgetd Cs eWaste stream per well(a) Analysis analysis and minimum well (dollar)

labor sampling(dollar) frequency

Dril Fluids (water-based) ............................................................... Bioassay (LC50) ........................................................................... 1.000 1/mo.(b) ......... 2,000Mercury, total ........................................................................ 50 1/mo.(b) 100Cadmium, total ............................................................................... 50 1 /mo.(b) ......... 100Diesel Detection ............................................................................ 75 (b)................... 150Static Sheen ................................................................................... 25 (c) .................... 250

Drill Cuttings (from water-based drilling fluids) .......................... Static Sheen ................................................................................... 25 (d) .................... 500

Total cost per well ......................................................................................................................................................................................................................... . $3,100

(a) Assumed drilling campaign of 35calendar days with 20 days of actualdrilling time.

(b) Twice per well.(c) Each day of discharge (assumed

every 2nd day of drilling).Id) Each day of drilling.

IV. Revised Industry Profile andEconomic Analysis

A. Industry Profile

Since the proposal of August 26, 1985(50 FR 34592), the Agency has updatedthe forecast of offshore oil and gasactivity. This updated forecast replacesthe projections developed for theproposal and presented in EPA's reporttitled "Economic Impact Analysis of

Proposed Effluent Limitationsand •Standards for the Offshore Oil and GasIndustry", EPA 440/2-85-003, July 1985.Those projections were based upon a1984 Department of Energy/EnergyInformation Administration (DOE/EIA)production forecast.

The Agency's revised projections arepresented in the Economic ImpactAnalysis for this notice which is

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available in the record for thisrulemaking. The revised projections-arein response to recent changes in.worldoil prices and to the comments on .theproposed regulations made by theOffshore Operators Committee (OOC) inFebruary of 1986. The new OuterContinental Shelf (OCS) forecast hasbeen developed using Department ofInterior/Minerals Management Service(DOI/MMS) sophisticated productionprojections. Three alternative oil pricescenarios have been analyzed: one at$32, one at $21, and one at $15 per barrelof oil.

EPA's updated projections of OCSoffshore oil and gas activity rely on the30-year forecasts of oil and gasproduction developed by the MineralsManagement Service. MMS developedits forecast based upon the data used inMMS' Environmental Impact Statementfor the Proposed 5-year OuterContinental Shelf Oil and Gas LeasingProgram (1987-1992), MMS 86-0127. Inthat report, MMS estimated "conditionalresources" for 21 OCS regions, assuminga market value of $32 per barrel of oil(1986 dollars). These conditionalresources represent the mean amount ofoil and gas reserves that areeconomically recoverable from theleased areas, given that explorationconfirms the presence of hydrocarbonreserves. The probability of findingreserves varies from region to region. Anestimate of the expected resources to bedeveloped in each leased area can beobtained by multiplying the probabilityof finding reserves (estimated by MMS)by the conditional resource estimates.Using this resource estimate, and rules-of-thumb regarding the amount of time ittakes to develop the resources in eacharea, MMS has developed a schedule ofresource production for the 1987-1992lease sales.

To develop the full 30-yearprojections, MMS used its estimates ofthe percentage of undevelopedresources to be leased during each of itssubsequent leasing periods. Forexample, if 25 percent of Alaska'sresources are expected to be leased In1987-1992, and 25 percent of Alaska'sresources are expected to be leased in1992-1996, then the resource projectionsfor the 1992-1996 lease would replicatethe resource projections for the 1987-1992 lease, with a 5-year lag. If 50percent of Alaska's resources were to beleased in 1992-1996, then the projectionswould be double those for the 1987-1992lease, with a 5-year lag.

Based on this methodology,' MMS haspublished 30-year projections of OCS oiland gas production for four majorregions: the Atlantic, Gulf of Mexico,

Pacific, and Alaska. These projectionsimprove upon the DOE/EIA forecastused by EPA at proposal for thefollowing reasons. First, the MMSforecast is based on a disaggregatedanalysis of resource potential and leaseactivity in each of the four regions.Second, the DOE/EIA forecast did notextend beyond 1995 while the MMSforecast extends to 2015; thus the MMSforecast increases the accuracy of theAgency's projections to 2000. Finally, theMMS forecast is easily amenable todifferent price scenarios. In its"Secretarial Issue Document" (1987),MMS developed alternative leasableresource estimates for various prices.Based on these resource estimates, theratio of resources at $21 per barrel to $32per barrel, and $15 to $32 per barrel areas follows:

Ratio of Ratio ofRegion $21/bbl to $15/bbl to

$32/bbl $32/bbl

Gulf .................................. 0.965 0.858Pacific .............................. 0.790 0.541Atlantic *.................. 0.514 0.327Alaska ............................. 0.098 0.0

These ratios mean, for example, thatusing the MMS resource estimates forthe Pacific OCS at $32 per barrel as thebasis (i.e., MMS projections at $32 perbarrel equal 100 percent), the Agencyestimates that 79 percent of these Pacificresources would be developed if theprice of oil fell to $21 per barrel. "Similarly, if the price fell from $32 to $15per barrel, the Agency projects that itwould make economic sense for the oiland gas industry to develop 54.1 percentof those Pacific resources. These ratioswere used to develop the twoalternative forecasts from the $32 perbarrel forecast.

The Agency has aslo developed newprojections for the number of wellsdrilled in state offshore waters and thenumber and configuration of offshoreplatforms. The revised estimates reflectthe declining role of state waters in oiland gas drilling in the Gulf of Mexico.(Between 1967 and 1985 the state-to-federal ratio dropped about 30 percentevery seven years.) Drilling in the statewaters of the Gulf of Mexico isprojected to be 11 percent of federalproduction for the period 1986-1992 and8 percent for the period 1993-2000. Nostate water activity is projected in theAtlantic. Based upon drilling activity instate waters between,1980 and 1985, :,drilling in state waters is projected to be50 percent of the activity in federalwaters in the Pacific and 300 percent offederal activity in Alaska.

In the following discussion of theeconomic impacts of the regulation, onlythe results of the Agency's analysisbased on an average oil price for theyears 1986-2000 of $21 per barrel are-presented. At this price, an average of978 wells are projected to be drilledeach year. (If the average price of oil is$15 per barrel between now and theyear 2000, 807 wells are projected to bedrilled each year; if the oil price is $32per barrel, 1,178 wells would be drilled.)

B. Economic Impacts

At proposal, the Agency estimated thetotal annual cost of the selected drillingfluids and cuttings option at $36.7million (in 1986 dollars). Table 1presents the Agency's revised estimateof the cost of the proposed regulationsfor drilling fluids and cuttings whichnow totals $76.6 million annually. Theannual estimated cost of controllingdrilling fluids has increased from $27.7million at proposal to $71.1 million. Theannual cost of controlling drill cuttingshas decreased from $9.1 million to $5.5million. The revised estimates for theproposed regulations have increaseddespite some declines in components ofthe estimate (e.g., the number of wellsdrilled per year and the monitoring costsper well). The increase in the revisedcost estimates for the proposedregulations is due primarily to increasesin: (1) The percentage of the drillingfluids that would have to be transportedto shore for disposal ("barged") and (2)the per-well cost of barging drillingfluids. Barging costs are incurred whenthese drilling fluids fail the limitation ontoxicity or the prohibition on thedischarge of free oil. As indicated inTable 1, the estimated percentage ofdrilling fluids that would fail effluentlimitations and thus be barged hasincreased from 10 percent to 23 percentbased upon revised estimates of effluentlimitation failure rates discussed earlierin today's notice. The per-well cost ofbarging drilling fluids has increasedprimarily because the volume of themodel well drilling fluid system wasincreased from about 5300 to about 6700barrels as discussed earlier in SectionIII.

The Agency has identified fouralternative approaches for controllingoffshore drilling fluids and drill cuttingsdischarges. The term "approach" is usedto refer to any one of four particularscenarios for costing purposes which aredifferentiated by:

(1) The differing toxicity failure ratesfor water-based drilling fluids to whichno oil has been added, as presented inSection III.A. of this part of today'snotice, and

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(2] The differing sets of effluentlimitations for mercury and cadmium isdrilling fluids as presented in Section'II.D. of this part of today's notice. Thefirst approach, identified here as"Approach A" is the one that is mostsimilar to the regulatory optionproposed in 1985, but as explainedabove, that option has been recosted toincorporate comments the Agency hasreceived and updated information theAgency has gathered since proposal in1985. Approaches B, C, and D arevariations on Approach A, reflecting thedifferences as explained in Section IIIabove.

The four approaches are summarizedbelow:

Assump- Failuretions Toxicity

Rate for Totalwater- Limita-. annual

Approach based tions2 for cost ($00,fluids Hg & Cd 1986

(percent) dollars)

A.' ................. 15 1,1 $76,617B 2 1, 1 50,662C ............. 15 1.5, 2.5 66,113D .................... 2 1.5, 2.5 40,158

'Of the four approaches, Approach A is mostsimilar to the 1985 proposed regulatory option.

2 1. 1 means 1 mg/kg each mercury and cadmiumin discharged drilling fluids; 1.5, 2.5 means 1.5 mg/kg mercury and 2.5 mg/kg cadmium in dischargeddrilling fluds.

As shown in the last column of theabqve table, the total annual costs forthe four approaches range between $40.2million and $76.6 million. Costs aregiven in 1986 dollars here and on Tables1, 2, and'3 below because 1986 is themost recent year for which a consistentand complete set of data is available foruse in the economic impact analysismodel. (For reference, these total costsare estimated to range between $42.0million and $80.1 million in 1988 dollars,if they are adjusted for inflation usingthe Engineering News Record'sconstruction index for the first sixmonths of 1988.)

The technology basis and thelimitations of Approach A are similar tothose of the proposed regulation. Asshown on Table 2, the costs ofcontrolling fluids are more for A than forB is based on the assumption that moredrilling fluids pass the toxicity test, andthus, under Approach B, fewer wellsincur the cost of barging.

Table 2 also shows that the costs ofApproach C are less than the costs ofApproach A [and the costs of D are lessthan the costs of B). Approaches Aand

B cost more because they includelimitations on the mercury and cadmiumcontent of discharged drilling fluids at amaximum (no single sample to exceed)concentration of 1 mg/kg each on a dryweight basis in whole drilling fluid. Thislimitation is estimated to increase thecost of barite by 15 percent, due toincreased costs for transporting andsegregating "clean" barite for use inoffshore drilling. The annual cost of thisbarite limitation is $10.5 million (in 1986dollars). Approaches C and D cost lessbecause they contain less stringentlimitations for mercury and cadmium.The 1.5 mg/kg mercury and 2.5 mg/kgcadmium limitations are estimated to beachievable at no additional cost,because they are based on the use ofbarite containing no more than 3 mg/kgof mercury and 5 mg/kg of cadmium.Thus, current supplies of barite foroffshore drilling can meet thesealternative limitations.

The estimated costs for approaches A,B, C, and D are all higher than theestimated cost of the proposal option.However, all four approaches presentedin this notice are economicallyachievable. The Agency's economicimpact notice are economicallyachievable. The Agency's economicimpact analysis compares the cost of oiland gas drilling in the absence of anyBAT/NSPS regulations (i.e., the basecase) to the cost of drilling witheach ofthe regulatory approaches-A, B, C, andD. The results of this analysis aresummarized in Table 3 for a 12-well, oil-only model platform in the Gulf ofMexico. Comparing compliance costs tothe base case, drilling costs for a typicalwell would increase between 1.03percent (for Approach D) to 1.95 percent(for Approach A). With the regulation,the net present value of a typical drillingproject in the Gulf of Mexico woulddecline between 1.5 and 3.0 percent, andthe cost of producing a barrel of oilwould increase between four and eightcents. For a major oil company (which isthe typical participant in offshore oildrilling projects), the debt incurred dueto any of the four regulatory approachesrepresents only 0.01 percent of thecompany's net worth. As shown onTable 3, the cost of the regulation alsohas no appreciable impact on any of thefinancial ratios examined for these oilcompanies, including: the current ratio,the long term debt-to-equity ratio andthe debt-to-capital ratio. The Agency'sanalysis shows that the economicimpacts of the regulation are notsubstantial, and thus any of the

approaches presented in this notice areeconomically achievable.

C. Cost-Effectiveness

In addition to the foregoing analyses,the Agency has performed a cost-effectiveness analysis of the two levelsof cadmium and mercury limitationspresented in today's notice. Table 4Apresents the cost-effectiveness of thesetwo levels (Approaches A and C) basedon the assumption of a toxicity failurerate of 15 percent for those water-baseddrilling fluids to which no oil has beenadded. Table 4B presents the cost-effectiveness of.the same levels oflimitations for cadmium and mercurybut with a toxicity failure rate of 2percent for those water-based drillingfluids to which no oil has been added(Approaches B and D).

According to the Agency's standardprocedures for calculating cost-effectiveness, on each of the tables theapproaches have been ranked in orderof increasing pound-equivalents (PE)removed. The pound equivalentsremoved for each approach werecalculated as the number of pounds ofpollutants removed by implementingeach approach weighted by the relativetoxicity of those pollutants. The resultsof these calculations are shown in thesecond columns of Tables 4A and 4B.(The "Cost-Effectiveness Report," whichis available in the record of thisrulemaking, supports this presentation,describes the cost-effectivenessprocedures in detail, and presents thetoxic weights used for each approach.)Cost-effectiveness is calculated as theratio of the incremental annual cost tothe incremental pound equivalentsremoved by the levels of control shownin the tables. So that comparisons of thecost-effectiveness among industries maybe made, the annual costs are convertedto 1981 dollars.

The cost-effectiveness of theregulatory approaches is shown in thelast column of Tables 4A and 4B below.All approaches are cost-effective:

Assuming a failure rate of 15 percentas shown on Table 4A, Approach C is$69 and Approach A is $19 per poundequivalent removed.

Assuming a failure rate of 2 percent asshown on Table 4B, Approach D is $54and Approach B is $16 per poundequivalent removed.

These costs are well within the rangeof the cost-effectiveness of new sourceperformance standards for otherindustries.

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TABLE 1.-COSTS AND OTHER SIGNIFI-CANT PARAMETERS OF PROPOSAL OP-TION AND OF COMPARABLE APPROACHA, DRILLING FLUIDS AND CUTTINGS

[1986 dollars]

At proposal RevisedParameter 1985 for estimate for

selected comparableoption approach A

Number of wells drilledannually ....................... 1,166 978

Average price of oilper barrel 1985/6 to2000 : .................... $32 $21

Percent barged:Drilling fluids ............ 10% 23%Drilling cuttings ........ 10% '7%

TABLE 1.-COSTS AND OTHER SIGNIFI-CANT PARAMETERS OF PROPOSAL OP-TION AND OF COMPARABLE APPROACHA, DRILLING FLUIDS AND CUTTINGS-Continued

[1986 dollars]

At proposal RevisedParameter 1985 for estimate forselected comparable

option approach A

Average cost ofbarging per wellwhere barging isrequired:

Fluids ........................Cuttings ...................

Total barite costs ............Monitoring costs per

well ...................

$113,000$69,000

$11,200,000

$3,734

$251,000$73,000

$10,504,000

$3,100

TABLE 1.-COSTS AND OTHER SIGNIFI-CANT PARAMETERS OF PROPOSAL OP-

TION AND OF COMPARABLE APPROACHA, DRILLING FLUIDS AND CUTTINGS-Continued

[1986 dollars]

At proposal RevisedParameter 1985 for estimate forselected comparable

option approach A

Total annual costs:Fluids .......... $27,664,000 $71,140,000Cuttings .................. $9,072,000 $5,477,000Total .......................... $36,736,000 $76,617,000

Includes both cuttings associated with water-based fluids (about 3%) and cuttings associated withmineral-oil based fluids.

TABLE 2.-REGULATORY COST OF ALTERNATIVE POLLUTION CONTROL APPROACHES

[$000, 1986 dollars]

Alternative pollution control approachesParameterApproach A Approach B Approach C Approach D

Drilling fluid costs ......................................................................................... .................................................................... $71,140 $45,185 $60,636 $34,681Clean barite ................................................................................................................................................................ .. 10,504 10,504 0 0Mineral oil substitution for diesel oil ............................................................................................................................... 1,706 1,706 1,706 1,706Static sheen test failure ................................................................................................................................................... 8,288 8,288 8,288 8,288Toxicity test failure ............................................................................................................................. ............. I ................ 48,099 22,144 48,099 22,144M on itoring costs ................................................................................................................................................................ 2,543 2,543 2,543 2,543Drill cuttings costs ............................................................................................................................................................ 5,477 5,477 5,477 5,477Static sheen test failure .......................................................................................................................................... .... 1,735 1,735 1,735 1,735No discharge with use of oil-based muds ........................................................... : ........................................................ 3,253 3,253 3,253 3,253M onitoring costs ................................................................................................................................................................ 489 489 489 489Total annual costs I ...................................................................................................................................................... 76,617 50,662 66,113 40,158Average costs per well drilled .......................................................................................................................................... 78 52 68 41Percent of drilling fluids barged ..................................................................................................................................... 23.3% 12.5% 23.2% 12.5%Percent of drill cutig bage 2. . . . . . . . . . . . .%67 6.7% 6.7%Pecn fdilcuttings barged2 .................................................................................................................................... 6.7% 6.7% , .%67

'For 978 wells per year, based upon average oil price of $21 /bbl.2 Includes both cuttings associated with water-based fluids and cuttings associated with mineral oil-based fluids.Source: EPA estimates.

TABLE 3.-ECONOMIC IMPACTS OF THE OFFSHORE OIL AND GAS REGULATION ON MUDS AND CUTTINGS, 1986-200 0a

[Selected Paramenters]

Total " Change in drilling Project Impacts; 12-wll, oil' Impacts for a typical major oil company fannual costs per well only platform in the Gulf ofcost of Mexico Change Reg. debt Current Long Debt toregIula- in compared to: ratio d term capital"

tion Change Cost per barrel of annual debt toAprahbin NPV oilc debt Total Net equity

ApproachDollar w/Reg. Assets worththou- Percent vs. NPV

Dollar sand w/o Percent D la ecnmillions Reg. Dollar PercntcDlla~change millions Percen rent Percent

Percent

A... ......................... 76.6 78 1.95 -3.25 21.44 0.37 2.12 0.006 0.014 1.11 35.6 23.8B ................ 50.7 52 1.30 -2.15 21.41 0.23 1.408 0.004 0.009 1.11 35.6 23.8C ................ ........ .66.1 68 1.70 -2.81 21.43 0.33 1.83 0.005 0.012 1.11 35.5 23.8D ....................................................... 40.2 41 1.03 -1.71 21.40 0.19 1.11 0.003 0.007 1.11 35.6 23.8

Industry Average ................................................. $4,000 ......... $18,239 $21.36 ................. $35. 893 $15,314 1.11 35.5 23.8Baseline ........................................... ($000) ($000) $millions $ millions

NPV - net present value.Reg. - regulation.1 1986 dollars. Based on projected average oil price of $21 per barrel and 978 wells drilled per year for the years 1986-2000.b Approach A is the proposed approach. It is costed assuming a 15% increase in barite costs to meet mercury and cadmium limitations In the discharged muds

and a toxicity test failure rate of 15% for water-based muds with no oil added, Approach B is the same as A but assumes a toixity test failure rate of 2%. Approach Cis based on an alternative metals limitation in the stock barite and an assumed toxicity test failure rate of 15%. Approach D is the same as approach C except thetoxicity failure rate is 2%. (See Section II and IV of the notice for details.)

cIncludes transfer payments such as lease payments, royalties, oil and gas taxes, corporate income taxes. ,* Current asset/current fliabilities. Assume working capital financing.* Assumes debt financina

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TABLE -, A-COST-EFFECTIVENESS FOR OFFSHORE OIL AND GAS, DRILLING FLUIDS AND CUTTINGS-RANKED BY ANNUAL POUND

EQUIVALENTS (PE) REMOVED

[Assuming 15% failure rate]

[1981 dollars] 2

Total annual Incremental Incremental cost

Approach R Cost (1981 $) Cost (1981 $) effectiveness $/PE Removed PE removed PE (1981 $)

C urrent .......................... ..................................................................... 0 0 .................................... .................................... ..................................

C .......................................................................................................... 787,685 54,639 787,685 54,639 $69A .......................................................................................................... 1,237,607 63,320 449,922 8,681 $19

1 As explained in the text above and in the cost-effectiveness analysis report which supports this notice, Approaches A and C assume a 15 percent toxicity failurerate for water-based drilling fluids to which no oil is added.

2 Factor for converting costs in 1981 dollars to 1986 dollars is: 1.21 The cost-effectiveness is standardized in 1981 dollars to facilitate comparison amongnumerous regulated industries.

3 Approach A limits Hg and Cd to 1 mg/kg each in discharged drilling fluids. Approach C limits Hg to 1.5 mglkg and Cd to 2.5 mg/kg in discharged drilling fluids.

TABLE 4 B-COST-EFFECTIVENESS FOR OFFSHORE OIL AND GAS, DRILLING FLUIDS AND CUTTINGS-RANKED BY ANNUAL POUNDEQUIVALENTS (PE) REMOVED

[Assuming 2% failure rate]

11981 dollars] 2

Total annual Incremental Incremental costApproach cost (1981 $) PE removed effcost (1981 $) ectiveness $/

PE removed ($000) ($000) PE (1981 $)

C urrent .............................................................................................. . 0 0 .........................................................................................................D ......................................................................................................... 610,939 33,188 610,939 33,188 $54B ......................................................................................................... 1,167,850 41,869 556,911 8,681 $16

As explained in the text above and in the cost-effectiveness-anaysis report which supports this notice, Approaches B and D assume a 2 percent toxicity failurerate for water-based drilling fluids to which no oil is added.

I Factor for converting costs in 1981 dollars to 1986 dollars is: 1.21 The cost-effectiveness is standardized In 1981 dollars to facilitate comparison amongnumerous regulated industries.

2 Approach B limits Hg and Cd to 1 mg/kg each In discharged drilling fluids. Approach D limits Hg to 1.5 mg/kg and Cd to 2.5 mg/kg in discharged drilling fluids-

V. Environmental AssessmentInformation

A. Mercury and Cadmium in Barite andEnvironmental Consequences onAquatic Life

Mercury and cadmium are twopotentially toxic constituents of barite-containing drilling fluids. The potentialenvironmental impacts of the dischargesof these metals in drilling fluids havebeen investigated by the Agency (1).

Sediment mercury and cadmiumconcentrations resulting from barite-containing drilling fluid discharges wereestimated and evaluated to determineenvironmentally significant sedimentalterations. Specifically, the Agency'sstudy:• Assesses the degree to which

sediment levels of mercury andcadmium may be altered at the locallevel (e.g., within a 500 m radius of thedrilling facility):

* Assesses the degree to whichsediment levels of mercury andcadmium may be altered at the regional

level for three cumulative dischargescenarios;

e Evaluates environmentalconsequences of sediment enrichmentby mercury and cadmium with regard towhat is known concerning the biologicalavailability of these metals.

All modeled levels of mercury (1 and 3ppm) and cadmium (1 and 5 ppm) inbarite showed some increase insediments within 500 meters of themodel 58-well Gulf of Mexico platform(the model size facility selected for theenvironmental assessment). At lowbackground sediment levels (0.01 ppmfor mercury and 0.04 ppm for cadmium)and higher assumed levels of 3 ppm formercury and 5 ppm for cadmium inbarite, the average increase were inexcess of 2000% (an increase of 20 times)for mercury over 800% (an increase of 8times for cadmium. The averageincreases at the lower assumed levels ofI ppm for mercury and cadmium inbarite were over 600% and over 160%,respectively at low backgroundsediment levels. At high backgroundsediment levels (0.04.ppm for mercury

and 0.2 ppm for cadmium), the averageincreases in sediment wereapproximately 500% for mercury and160% for cadmium at higher specifiedlevels, and approximately 160% formercury and 25% for cadmium at lowerassumed levels (1 ppm each).

Because a large fraction of the drillingmuds is expected to be transferredbeyond the.immediate vicinity of theplatform, the cumulative impacts ofmultiple drilling were analyzed for threeregional scenarios: the Santa BarbaraChannel, a Louisiana continental shelfarea, and the entire Louisiana Gulf ofMexico lease area.

The estimated increase in addedbarite concentrations at the sedimentsurface after 24 years would be 1524ppm for the Santa Barbara Channel, 933ppm for the Louisiana shelf area, and272 ppm for the entire Louisiana leasearea. Ther analysis assumes typicalsediment mixing conditions, and that allsolids stay within the regional areasmodeled. At low background mercuryand cadmium sediment levels (0.01 ppm:

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for mercury and 0.04 ppm for cadmium)and barite containing 3 ppm of mercuryand 5 ppm of cadmium, the increases ofmercury and cadmium in the SantaBarbara Channel sediments wereestimated at 46% and 19% respectively.At high background sediment levels(0.04 ppm mercury and 0.2 ppmcadimum), the increases would be 11%and 4%, respectively. If barite controls 1ppm of mercury and cadimum theprojected regional increases are 15% and4% respectively for low backgroundsediment levels, and 3% for mercury and<1% for cadimum for high backgroundsediment levels.

For the Louisiana shelf and the entireLouisiana offshore lease area theresulting projected regional increases forthe same mercury and cadimum bariteand background sediment levels wereapproximately 2/ and 1/5 of the levelsestimated for the Santa BarbaraChannel due to lower estimated welldensity.

This analysis shows that barite couldbe a measurable source of mercury andcadmium near drilling platforms insediments if present at the dischargelevels used in this analysis, even if thesediment transport processes eventuallyremove some fraction of the barite fromthe shelf sediments and redeposit it indeeper offshore areas where theenvironmental impacts are expected tobe less signifiant.

The comments received from theindustry on the proposed regulationstated that the cadimum and mercuryassociated with drilling fluids arepresent as insoluble sulfides in bariteand have a very low bioavailability tomarine organisms.

The Agency recognizes that anincremental increase in sediment metalsdoes not necessarily translate into acomparable increase of impacts onmarine life. However, these data showthat mercury and cadmium dischargedwith the barite containing drilling fluidshave a potential to cause environmentalproblems in the marine environment anda potential for transport to humansthrough consumption of contaminatedseafood, especially shellfish.

The environmental consequences ofelevated local and regionalconcentrations of mercury and cadmiumdue to barite-containing drilling fluidsare difficult to judge, because manyaspects related to the environmentalfate of these metals in marineenvironment are not well understood.An extensive literature review wascarried out as part of this study on fateand effects of these metals on marineenvironments, especially with respect tobioavailability, bioaccumulation, andbiomagnification in the food chain.

Based on the U.S. Congress, Office ofTechnology Assessment (OTA) Report(2), the ability of a metal to affectmarine organisms depends primarily onits form (e.g., dissolved or particulate,bound to other substances or free), andthis is greatly affected by site-specificconditions. In their particulate form,most metals tend to adsorb onto otherparticles that eventually settle from thewater and are deposited as sediment.Once deposited in oxygen-poor,sediments, the chemical form of thesemetals is generally stable. However, ifthe sediments are subsequentlyoxygenated, some metals, includingcadmium, may dissolve and be slowlyreleased into the water column, and maybe taken up by non-benthic organisms.Sediments can be oxygenated (and alsoresuspended) by bioturbation, storms,and other disturbances. Metals also canbe released as a result of other changessuch as salinity fluctuation in estuaries.Microorganisms in sediments canmodify the slightly toxic inorganicmercury and convert it to highly toxicand volatile methyl mercury.

OTA's report (2) identified asignificant potential for transport of bothmercury and cadmium to humansthrough consumption of contaminatedseafood. Marine organisms can ingestmetals that are dissolved in the water orthey can ingest particulate matter ontowhich metals are adsorbed. Onceingested, some metals can pass throughthe gut and be excreted, while otherscross the gut membrane and accumulatein organismal tissue. Both cadmium andmercury tend to bioaccumulate inmarine organisms. Mercury in itsmethylated form is the only metalknown to biomagnify in successivelevels of the aquatic food chain. Evenwhen bioaccumulation is not a factor,significant quantities of metals canconcentrate in the gut and gills ofmarine organisms without actualabsorption into the tissues. This isespecially true for shellfish that filterlarge quantities of seawater and ingestsolid matter during feeding (e.g., oysters,clams, mussels).

Because people generally eat theseorganisms in their entirety, toxicsubstances can be passed to humanseven in the absence of bioaccumulation.This mechanism probably accounts formost instances of shellfishcontamination involving metals that donot bioaccumulate.

Results of investigation of sources,fates, and effects of metals nearmunicipal wastewater outfalls insouthern California coastal watersindicate that: (1) The largest portion ofmetals entering the system is in .particulate form, but a large portion may

be released into the dissolved phaseupon mixing with seawater and may becarried out of the region by prevailingcurrents; (2) despite these losses of thesolubilized fraction, the particulate andsediment concentrations of metals in thevicinity of municipal wastewateroutfalls are highly elevated; (3) filterfeeders (e.g., scallops, mussels) haveexhibited higher metal levels nearsources of contamination as comparedto "control" areas; (4) there is evidenceof bioaccumulation of metals in filter-feeding bivalves in the vicinity ofmarine outfalls; (5) concentrations ofcadmium in muscle tissue of dimersalfish tend to be less than in sediments,but the concentrations in the liver orhepatopancreas of animals could exceedthat of the sediments.

Analysis conducted by Trefrey et al.(3), investigating trace metals in bariteindicates that mercury is tightly boundin barite and not easily released.Cadmium, however, is more easilyleached from the barite than many othermetals.

None of the above data, however.provide conclusive evidence relative tothe stability or bioavailability ofmercury and. cadmium in barite-containing drilling fluids. Work iscurrently underway within EPA andNOAA to define the equilibriumpartitioning of metals in sediments, porewater, and organisms. Results of theseefforts are expected to aid in theevaluation of potential impacts ofmercury and cadmium and other metalsin barite-containing drilling fluids onaquatic organisms. However, thepartitioning of these metals from baritemay be quite different from thepartitioning from other discharges (e.g.,sewage particles) or from ambientsediments.

As discussed in previous sections ofthis notice, the Agency has found that asthe levels of mercury and cadmium inbarite are decreased, the other toxicmetals in barite are also found togenerally decrease. Arsenic, lead, zincand other toxic metals may also bereleased into the marine environment asa result of barite discharges. In addition,the levels of cadmium and mercury thatcan be expected to occur in sedimentsas a result of potential offshore drillingactivities will be dependent on the levelof drilling activity that will occur, theenergenics of the region, and thebackground levels of these metals in thesediment. All of these factors will varyfrom one region of the country toanother.

The Agency is continuing to evaluatethe environmental fate of mercury,cadmium and other toxic metals

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associated with barite to determine theimpacts of these discharges in themarine environment. The Agency is,therefore, soliciting new informationrelated to the occurrence,bioavailability, release,bioaccumulation, and other related dataon mercury, cadmium and other toxicmetals in barite and in drilling fluids.

B. Analysis of Shallow WaterDispersion Models

As part of the ongoing evaluation ofpotential impacts from offshore oil andgas discharges, discharge dispersionmodels were being examined as acomponent in an assessment of the fateand transport of drilling muds andproduced water in the marineenvironment. For the most part, modelshave been applied to dischargesituations in relatively deep waters(greater than 40 meters in depth); theirappropriateness and reliability in moreshallow waters (40 meters to mean hightide) is much less well known.

In addition to discharges occurring inthe deeper waters of the OuterContinental Shelf (OCS), producedwaters, drilling fluids, and other oil andgas discharges are released in ageographic zone that extends from thehigh tide line out to the OCS. In the Gulfof Mexico, where over 90% of alloffshore production takes place, thisgeographic zone includes the offshorearea extending 9 miles off the coast ofTexas and 3 miles off the coast ofLouisiana. Of all offshore wells drilledin State waters off the coasts of Texasand Louisiana, approximately 11% are inwater depths of greater than 20 meters,some 43% are in water depths of 10 to 20meters, and about 46% are in waterdepths of less than 10 meters.

Appropriate dispersion models fordischarges occurring in these shallowwaters need to be identified. In responseto this need, the Agency has analyzedexisting dispersion models to identifythe limitations of their shallow waterutility (4). Several potentially relevantdispersion models were identified andreviewed by the Agency to determinetheir applicability to shallow water,offshore oil and gas discharges (TableA). Of the models reviewed, some wererejected as not being appropriate for thetype and/or methods of discharge orreceiving waters. Although under othercircumstances these models have utility,they were judged to have limited,general application with regard toshallow water marine discharges, oiland gas discharges, or the type of datapresently available either for theseareas or types of discharges.

The remaining models were dividedinto three categories and analyzed in

more detail. The first category includesmodels concentrating primarily on thefate of discharged solids. These modelsmay also predict the fate of the liquidphase. However, in these models theliquid phase was considered as asecondary objective. The secondcategory includes models that dealprimarily with the liquid phase ofdischarges; often, these models addressthermal effects. The third categoryincludes models designed primarily toaddress discharges of toxics.

Table A. Models Reviewed for ShallowWater Dispersion Applicability

L Models that were reviewed, but werenot found relevant for these receivingwater areas, discharge types, oravailable data:

DIFHD (Army Corps of Engineers,1987)

UPLUME and ULINE (EPA, 1985)DYNTOX (EPA, 1983)HSPF (EPA, 1985)MINTEQ (EPA, 1984)PRZM (EPA, 1984)QUAL2E and QUAL2E-UNCAS (EPA,

1987)SWMM (EPA, 1987).

II. Models that were reviewed andconsidered for further study:

Category 1: Primarily Solid PhaseModels

OFFSHARE OPERATORSCOMMITTEE (OOC) MUDDISCHARGE MODEL (M.G.Brandsma et al., 1983)

A TIME-DEPENDENT, TWO-DIMENSIONAL MODEL FORPREDICTING THE DISTRIBUTIONOF DRILLING MUDSDISCHARGED TO SHALLOWWATER (EPA-2D) (Yearsley, 1984)

DIFID and DIFCD (Army Corps ofEngineers, 1987)

DRIFT MODEL (Runchal, 1983).Category 2: Primarily Liquid Phase

ModelsPDS MODEL (Pritch, Davis, and

Shirazi, 1974)UOUTPLM, UMERGE, and

UDKHDEN (EPA, 1985)(MODEN) Motts-Benedict.

Category 3. Primarily Toxic DischargeModels

EXAM 2 (EPA, 1985)WASP 3, EUTRWASP, and

TOXIWASP (EPA, 1986).1. Evaluation of Potentially AppropriateModels

Those models considered to bepotentially appropriate for dispersion ofdrilling fluids and produced water wereevaluated. Below, the majorcharacteristics and limitations of each

model are summarized and arecommendation as to the potentialapplicability of each for modelingshallow water dispersion of drillingfluids and produced water is provided.1.1 Primarily Solid Phase Models (Mud

Discharge Models)1.1.1 Mud Discharge (OOC) ModelCharacterization:-Time-dependent three-dimensional

model.-Calculates nearfield initial

development of dynamic plume.-LaGrangian treatment of diffusion

phase; tracks individual clouds.-Material settling out of dynamic

plume acts as source of Gaussiandistributed clouds.

-,Concentrations in water column foundby superposition of contributions fromnearby clouds.

-Concentration throughout watercolumn and on the bottom areprovided at any time.

-Developed specifically foi drillingmuds.

-Allows for variable topography, time-variant density and velocity profiles,and wide range of dischargeconditions.

-Diffusion coefficient calculation isdependent on surface and bottomconditions.

Limitations:-Highly dependent on diffusion

coefficient.-The model does not account for the

effects of flocculation of mud in Watercolumn.

-The algorithm used in the model tocause the early separation of finematerial near the discharge source(during-the jet phase) has notheoretical basis.

-The model cannot simulate thesituation where the plume descendsexactly vertically in shallow water orcombined with a much higher verticalto horizontal velocity ratio.

-Probably not appropriate whensurface waves induce significantvariations in water depth (10-20%).

-Current version does not coverproduced water; a revised model, notyet released, covers produced water.

Recommendation:-Applicable at depths greater than 5

meters.-Not applicable at depths less than 2

meters.-Uncertain applicability from 2 to 5

meters.1.1.2 EPA2-D modelCharacterization:

-- Time-dependent, two-dimensionalmodel.

-Assumes plume is vertically mixed.

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-Conservative in the nearfield inshallow water (assumes completemixing); may not be conservative indeeper water (i.e., where completevertical mixing is progressively lessvalid).

-More applicable to the farfield.Limitations:-Does not include initial mixing.-Highly dependent on turbulent

diffusion.-Not conservative for extremely short

time scales or deeper water (seeabove).

Recommendation:-Appropriate, especially for very

shallow water (2 meters or less), butneeds to be qualified.

1.1.3 DIFID and DIFCD modelsCharacterization:-Cover instantaneous and continuous

discharge. Modified to includeconcentration profiles with depth.Developed for dredge muds.

Limitations:-Only consider bottom deposition and

horizontal distribution.-Need to know how deep the plume is.Recommendation:-Not appropriate because superseded

by other models (OOC model forexample).

1.1.4 DRIFT modelCharacterization:

-Joint probabilistic trajectory model forcurrent speed and direction.

-Focuses on bottom deposition.Limitations:-Calculation does not depend on

diffusion coefficients.-Covers only low rate of cuttings*

discharge.Recommendation:-May be appropriate, but has limited

utility.1.2 Primarily Liquid Phase Models1.2.1 PDS modelCharacterization:-The only model that considers surface

plumes.-Covers surface discharge and assumes

plume floats on surface and there isno interaction with bottom.

-Perhaps useful with low salinity andhigh temperature.

Limitations:-Does not apply if drilling material is

negatively buoyant.-Model does not include sediment or

boundary effects.Recommendation:

-Appropriate for surface plumes.1.2.2 OUTPLM and UMERGE modelsCharacterization:-UMERGE is a revised version of

OUTPLM model.

-Two-dimensional, multiple portversion of OUTPLM model.

-Discharges from several ports mergetogether in a "top-hat" profile.

-Current speed and direction areconstant with time.

Limitations:-Does not include development zone.-Current must be normal to line of

diffuser.-Assumes no interaction with surface

or bottom boundaries.-Does not account for settling of solids

or ambient stratification.1.2.3 UDKHDEN modelCharacterization:-Three-dimensional model.-No restrictions on discharge direction

with respect to ambient current.-Diffuser, single or multiple port.-Allows for variable density

stratification and variable current.Limitations:-Assumes currents and ambient

density are constant with time.Recommendation:-Appropriate for negatively buoyant

liquid phase discharges until plumereaches to within one-half to oneplume width of the bottom.

1.2.4 MOBEN modelCharacterization:-Two-dimensional model.-Liquid phase, vertically integrated

discharge over shallow depth.-Assumes constant depth.-Discharge from rectangular trough.Recommendation:-May be useful in shallow water.1.3 Primarily Toxic Discharge Models1.3.1 EXAM 2 model-May have some applicability because

of eutrophication and dissolvedoxygen components.

-Probably is concentration-dependent.-Need to convert measured effluent

BOD to theoretical values.

-Input data availability is questionable.1.3.2 WASP 3, EUTRWASP, and

TOXIWASPCharacterization:-Includes hydrodynamics, conservative

mass transport, eutrophication-dissolved oxygen kinetics, and toxicchemical-sediment dynamics.

-Multidimensional and time variablecapabilities.

-Simulates conventional and toxicpollution.

Limitations:-User must write applicable kinetic

equations for a given problem.-Simulates transport and

transformation of a single chemical.-Chemical concentration must be near

trace levels.-Requires user to specify flow fields.

Recommendation:

-Limited utility for a multi-constituenteffluent, such as drilling fluids.

2. Recommended Modeling Approach

The OOC model, which wasdeveloped principally for drilling muds,appears to be potentially applicable forshallow water dispersion of drillingfluids at depths greater than 5 meters,and possibly to 2 meters. At any depthbelow the fixed depth to which the OOCmodel is found to be inappropriate, theEPA Time-Dependent, Two-DimensionalModel for Predicting Distribution ofDrilling Muds Discharged to ShallowWater (EPA2-D) should be used. Whilethis model is appropriate at a depth of 2meters, it may require additional fieldverification for shallower water.

The EPA liquid phase models,particularly UMERGE and UDKHDEN,are potentially applicable for modelingnonsurface or vertically downwarddischarge of produced water. Forsurface discharge, the PDS model maybe appropriate; it is the only model thatconsiders surface plumes. When theplume reaches to within one-half to oneplume width from the surface or bottom,(the point at which UMERGE andUDKHDEN are no longer appropriate), atwo-dimensional model such as theMotts-Benedict (MOBEN) model or theEPA2-D model should be used.

As a part of this notice, the Agency isrequesting comments on the list ofmodels reviewed, the models selected asbeing appropriate for shallow waterdischarges of drilling fluids andproduced water, and the modelscenarios Used to assess both modelsbehavior and effluent behavior. Thedischarge, operational, and ambientconditions that were used as input to theselected models and the results of modelruns are presented in the draft reporttitled "Analysis of Effluent DispersionModels Potentially Applicable toShallow Water Discharges from Oil andGas Activities" (4), which is available inthe record of this rulemaking.

References for Section V(1) U.S. EPA, 1987, Estimates of Degree of

Sediment Alteration Associated with VariousLevels of Mercury and Cadmium in Barite.

(2) U.S. Congress, Office of TechnologyAssessment, Wastes in MarineEnvironments, OTA-0-334 (Washington, DC.:U.S. Government Printing Office, April 1987).

(3) Trefrey, J.H., et al., 1986, "Draft andFinal Report to the Offshore OperatorsCommittee: Forms, Reactivity, and " *Availability of Trace Metals in Barite."

(4) U.S. EPA, 1988, "Analysis of EffluentDispersion Models Potentially Applicable to

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Shallow Water Discharges from Oil and GasActivities."

Part 2

I. Summary

EPA is currently reconsidering theprohibition on the discharge of drillcuttings that contain oil-based drillingfluid, as proposed in the August 26, 1985proposal and is considering as analternative the development of an oilcontent limitation for drilling wastestreams. "Oil content" would be used asa non-conventional indicator pollutantfor the BAT and NSPS levels to controlthe discharge of priority and non-conventional organic pollutants presentin the hydrocarbons that are added todrilling fluids, both as a lubricity agentand for spotting purposes, and in thehydrocarbons from formation fluids thatare entrained in the drilling fluid. Thesesame priority and non-conventionalpollutants are present in the associateddrill cuttings waste stream and may besimilarly controlled by an oil contentlimitation. An oil content limitationwould apply to the discharged drillingwaste and would not differentiatebetween diesel oil or mineral oil. The oilcontent measurement would beperformed according to the "retort-gravimetric" procedure discussed insection IX of this part and is presentedin Appendix A of this notice.

Specifically, the Agency is nowconsidering the establishment of an oilcontent limitation of up to 1.0% byweight (whole sample basis) for drillcuttings based upon application ofthermal distillation, thermal oxidation,or solvent extraction technologies. Anoil content limitation would apply todrill cuttings associated with bothwater-based and oil-based drilling fluidsand would apply as a maximum value(no single sample to exceed). TheAgency believes that the technologiesdiscussed below are technologicallyfeasible to implement for the treatmentof drill cuttings to reduce oil content.

The Agency also has considered theestablishment of an oil contentlimitation for oil-based drilling fluids.The Agency has tentatively rejected thisapproach because existing regulations(BPT) effectively prohibit the dischargeof oil-based drilling fluids.

Finally, the Agency has consideredthe establishment of an oil contentlimitation for waste-based drilling fluidsthat contain added or entrained oil. TheAgency believes that processing rateand storage limitations may make itimpracticable to implement an oilcontent limitation for water-baseddrilling fluids based on using any ofthese technologies to treat water~based

drilling fluids at offshore drilling sites.These factors are discussed in Section Vof this part of today's notice.

The technologies discussed in thispart of the notice would achieve aresidual oil content in the processed.cuttings which would be lower thanthose achieved using cutting washer(i.e., BPT) technology. The currentregulation prohibits the discharge of"free oil" as evidenced by the presenceof a visible sheen upon the receivingwater after discharge of the drillingwaste.

The BAT and NSPS regulations fordrill cuttings proposed on August 26,1985 would prohibit the discharge ofdrill cuttings associated with the use ofan oil-based drilling fluid. Severalcommenters on the proposed regulationsargued that the discharge of cuttingsassociated with oil-based fluids shouldbe allowed if the oil content werecontrolled to acceptable levels, i.e., thedischarged cutting did not violate thesheen test used to detect free oil. TheAgency proposed to prohibitunconditionally the discharge of suchcuttings because of substantial historicalexperience with the seepage of oil fromsuch cuttings after they weredischarged. Though such cuttings maycomply with the BPT "free oil"limitation upon discharge, they couldrelease substantial amounts of oil fromtheir location on the ocean floor longafter the original discharge occurred.

Allowing the discharge of treated drillcuttings associated with oil-baseddrilling fluids, as opposed to aprohibition on their discharge, couldlead to the continued development ofcontrol/treatment technologies, reducedregulatory compliance costs for theoffshore segment of the industry, andalleviation of potential problems withland disposal of drilling wastes incoastal areas.

The remainder of this part of today'snotice presents more detailedinformation and discussion on oilcontent limitations for drilling wastes.After consideration of the commentsand any additional data received duringthe comment period on this notice inaddition to information in the existingrulemaking record, the Agency maydecide to propose effluent limitationsguidelines and standards for the controlof oil content in drilling wastes.

II. Background

As stated elsewhere in this notice, onJuly 2, 1986 EPA Regions IV and VIissued a general National PollutantDischarge Elimination System permit(the General Permit) regulating oil andgas exploration, development, andproduction activities in federal waters of

the Gulf of Mexico. One of therequirements of the general permit is aprohibition on the discharge of drillcuttings associated with the use of oil-based or inverse emulsion fluids.

During the comment period on thedraft general permit, SEDSCO, Inc. (nowThermal Dynamics, Inc.) commentedthat it had developed a treatmenttechnology which would be moreeffective in removing residual oil fromdrill cuttings than the previouslyavailable treatment methods. However,at that time, EPA decided that sufficientdata were not available on the newtechnology to justify an alternativeeffluent limitation. The general permitimplemented the "no discharge of freeoil" requirement by prohibiting thedischarge of any drill cuttingsassociated with oil-based muds. Thefinal general permit for the federalwaters of the Gulf of Mexico was issuedon July 9, 1986.

On August 15, 1986, ThermalDynamics, Inc. (TDI) sought to stay thegeneral permit limitation for the drillcuttings waste stream. TDI argued that,in view of its newly developedtechnology, prohibiting the discharge ofdrill cuttings associated with an oil-based drilling fluid was unnecessarilystringent as an implementation of the"no discharge of free oil" limitation. TDIstated that sufficient data wereavailable to EPA to demonstrate thatsubstantial reductions in the oil contentof cuttings could be achieved by termaldistillation. TDI stated that this newtechnology could reduce the oil contentof drill cuttings to a level equivalent tothe "no discharge of free oil" limitation.

At the time Thermal Dynamics- soughtto stay the general permit limitation,only limited information was availableon the efficiency of those technologies inactual use. EPA Region VI issued a"demonstration" permit to an oilcompany to allow for field data to begenerated on the operation of a thermaldistillation treatment system. A vendor-supplied thermal distillation unit wasused to treat drill cuttings producedduring actual drilling operations withoil-based drilling fluid. The cuttingwaste stream, processed cuttings, andassociated by-product waste streamswere characterized for oil content,solids content, priority pollutantorganics and metals, RCRA (ResourceConseration and Recovery Act) ICRcharacteristics (ingnitability, corrosivity,reactivity) and acute toxicity (LC50).

In view of the additional informationobtained on this and other technologiesfor treating drilling wastes, EPA isreconsidering the proposed prohibitionon the discharge of drill cuttings that

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Federal Register / Vol. 53, N~o. 204 / Friday, October 21, 1988 / Proposed Rules

contain oil-based drilling fluid. EPA isnow considering alternatives to theproposed discharge prohibition.

One alternative being consideredwould allow the discharge of treateddrill cuttings that meet a specified oilcontent limitation. Drill cuttingsdischarges would still have to achievethe BPT limitation of 'no discharge offree oil'.

III. Description of Technologies forControlling Oil Content of DrillingWastes

The preamble to the 1985 proposedregulations include a discussion ofcuttings washer technology and itseffectiveness for reducing the oil cententof drill cuttings. The Agency found thatcuttings washer systems that were -studied were reported to reduce the oilcontent of drill cuttings toapproximately 10% by weight. However,the Agency rejected the use of cuttingswasher technology as a basis for an oilcontent limitation because it believedthat the cuttings washer technology didnot achieve a reduction in oil content ofthe drill cuttings sufficient to meet theBPT requirement of 'no discharge of oil'.Since 1985 the development and use ofcuttings washer technology appears tohave diminished, possibly due to therelatively high residual oil content of theprocessed cuttings and problems withproper disposal of by-product water/oil/detergent wastes.

After the proposed regulations werepublished, the Agency investigated othertechnologies for reducing the oil contentof drilling wastes. These technologiesfall into two general classes. In oneclass are thermal processes (thermaldistillation or thermal oxidation). In theother class are solvent extrationprocesses. All of the technical and costinformation provided by the vendors ofthese technologies and additionalinformation collected by the Agency isavailable in the public record for thisrulemaking.

The Agency has evaluated vendortechnical information and collectedperformance data on the treatment ofdrilling wastes, specifically drill cuttingsassociated with the use of oil-baseddrilling fluids, by thermal distillation.This technology appears to betechnologically feasible to implement forthe reduction of oil contained in drillingwastes. Based on data obtained on thesetechnologies, the costs on a per well.basis of onsite treatment using thermaldistillation or solvent extration appearto be in line with the cost estimates fortransport to shore and land disposal ofdrilling wastes.

The basic thermal distillation processhas been adapted in variations by

several vendors. The process removeshydrocarbons and-water from drillingfluids and drill cuttings. There are threetypes of thermal systems known to theAgency that are available for thetreatment of drill cuttings.

T-1 Process

One type of system to treat drillingwastes consists of electrically heatedchambers in which the drilling wastesare exposed to controlled heat sufficientto volatilize the residual oil and water inthe wastes. (This will be referred to asthe "T-1" process). The electrical energyrequired by the process is provided bygenerators at the treatment site.

The processed wastes in the form of agranular material are cooled andslurried by mixing with seawater andare then discharged to the ocean. Thewater and hydrocarbon vapors of drivenfrom the wastes are condensed and thenseparated in an oil/water separator. Thehydrocarbons recovered can potentiallybe recycled and reused in active mudsystem, subject to meeting thespecifications for oil additives to themud. Alternatives to recycling therecovered hydrocarbons would be todispose of them separately or to marketthem for other purposes (e.g., heatingfuel). If the revovered water meetseffluent limitations for produced water,if could be suitable for discharge. It therecovered water does not meet theseeffluent limitations if may beappropriate to introduce it to theproduced water treatment system. Ifthere are no production facilities at thesite the recovered water may need to betransported to another facility foradequate treatment or handling. Exhaustgases from the heating chambers in thethermal distillation unit and from thecondenser would be treated to achieveappropriate air emissions standards.

These units are mobile and can beinstalled and operated on a rig toprocess wastes onsite. Full-size unitshave been field tested to treat drillcuttings. The T-1 process has been usedto treat drill cuttings at an offshorefacility in the Gulf of Mexco, in theNorth Sea, onshore in Alaska, and atonshore drilling sites in the Netherlands.At these locations, full-size units wereused to treat drill cuttings for oil contentreduction. The results of samplingperformed by the vendor and by EPAindicate that the process can achievesignificant reduction in the oil content ofdrill cuttings. Observations to dateindicate that this technology is capableof reducing oil content levels to 1% orless by weight in processed cuttings(associated with oil-based muds) andthat geographic location is not a factoror restriction in locating and operating

this technology. (Source: Vendor andEPA sampling data).

A thermal distillation unit of this typewas tested under the demonstrationpermit issued by EPA. Performance dataon this unit is presented and discussedin Section VII -of this part of the notice.

T-2 Process

Another variation of the thermaldistillation process has been developedfor the reduction of hydrocarbons indrilling fluids and drill cuttings. (Thiswill be referred to as the "T-2" process).The drilling wastes are routed to thedrying section of the process wherehydrocarbons and water are driven fromthe wastes. The water andhydrocarbons driven off the cuttings arepassed through condensers and theresultant liquid is processed to separatethe oil from the water. The oil is placedin storage for further purification andthe water is processed to effectadditional separation of oil from thewater. If the recovered water meetseffluent limitations for produced water,it could be suitable for discharge. Theunit has been used for offshoreoperations on mobile drill units,platforms or barges.

A prototype "demonstrator" unit hasbeen used to process drill cuttings. Anoil content of less than 0.5% by weightwas reportedly achieved in test with thisunit. (Source: Vendor-suppliedinformation). A full-scale unit has notyet been tested under actual filedconditions.

T-3 Process

A third variation on the thermaldistillation technology has beendeveloped. This process uses indirectheating to vaporize water andhydrocarbons adhering to drillingwastes. (This will be referred to as the"T-3" process). In this process, drillingwates are fed to a blender whichmaintains a homogeneous slurry feed tothe process unit. A closed heat transfersystem around the processing unitprovides the heat required to vaporizethe water and hydrocarbons from thedrilling waste. The proposed source ofheat is exhaust gases from the rigelectricity generator. The processedwastes are dry and granular in nature.The vaporized water and hydrocarbonsare condensed for their recovery. Thecondensed hydrocarbons and water canbe separated with potential for thehydrocarbons to be reused in the activemud system subject to meeting thespecifications for oil additives to themud. If the recovered water from theseparator meets effluent limitations for

41375



produced water, if could be suitable fordischarge.

The process is implemented usingaskid-mounted mobile unit which isreportedly suitable for use eitheroffshore or onshore. This version ofdistillation technology has been testedon a pilot scale basis but not on a full-scale basis. Pilot-scale tests on drillingwastes are reported to have producedcuttings consistently with an oil contentof 6% or less by weight. (Source:Vendor-supplied information).

T-4 Process

A thermal oxidation process has alsobeen developed which can be used totreat drilling wastes. (This will bereferred to as the "T-4" process). Theprocess consists of a direct fired,countercurrent rotary kiln where thewastes are thermally oxidized attemperatures typically in the range of1600 F to 2500 F. The kilns can be over200 feet in length. The dried solidsproduced in this process are reportedlysuitable for use as aggregates or fillmaterials. The hydrocarbons drivenfrom the wastes are partially oxidized inthe kiln, while virtually completecombustion is achieved in an oxidationchamber and afterburner. At least twoof these facilities are known to becurrently operating on the Gulf ofMexico coast. However, due to the scaleof the equipment as currentlydemonstrated, this process can not beimplemented offshore or moved fromsite-to-site. However, drilling wastescould be transported to such land~basedfacilities for processing.

SE Process

In addition to .the thermaltechnologies described above, a processbased on solvent extraction technologyhas been developed to treat drillingwastes for the reduction of oil content.(This will be referred to as the "SE"process). In this process, the drillingwastes are directed to an extractioncolumn and contacted with solvent toextract the oil. The oil-laden solventflows from the extractor column to anevaporator, a separation column and aseparator where the oil and solvent areseparated. The oil phase flows to thefluidizing oil holding tank and thesolvent is recycled to the process. Oillevels as low as 0.3% by weight in theprocessed wastes are reportedlyachieved using this process. (Source:vendor-supplied information). Whenused to process used drilling fluids, onevendor reports that the resultant mudsolids can be recovered for reuse.

The types of solvents have been usedin the solvent extraction processesinvestigated by the Agency-

chlorofluorocarbons and carbon dioxide.Either type of solvent reportedly willserve the operational needs of theprocess. Although the solvents are usedand recovered in a closed-type system,there is potential for some solvent lossto the atmosphere. The Agency does nothave quantitative information on theamount of such solvent losses fromthese processes. The Agency isparticularly concerned about thepotential for losses ofchlorofluorocarbon-type solvents fromthese processes to the atmospherebecause they contribute to depletion ofthe stratospheric ozone layer, and theAgency has recently limited theirproduction. (53 FR 30566) The Agency istherefore soliciting comment andadditional information to assess thispotential, to quantify the rate andamounts of such losses, and todetermine whether there are acceptablealternatives to use ofchlorofluorocarbon-type solvents inthese processes.

IV. Applicability of Thermal andSolvent Extraction Technologies forTreating Drilling Wastes

A. Drill CuttingHydrocarbons can be present in the

drill cuttings as a result of theintroduction of oil additives to thedrilling fluid system for lubricity andspotting purposes and the entrainmentof formation hydrocarbons in the drillingfluid system. When the drill cuttings areseparated from the drilling fluid system,they contain some of the drilling fluidsand drilling fluid system additives (e.g.,oil). The drilling fluids and oil additivesthat are carried into the drill cuttingswastes after their removal from the bulkmud system by rig shale shakers andother separation equipment areconsidered to be part of the drill cuttingswaste stream.

Based upon performance and costinformation provided by several vendorsof thermal and solvent extractiontechnologies, it appears to betechnologically feasible to implementone or more of these technologies atoffshore drilling sites for the reductionof oil content in drill cuttings. The costs(on a per well basis) of onsite treatmentusing thermal distillation or solventextraction appear to be in line with thecost estimates for transport to shore andland disposal of the same wastes. Thisapplies to drill cuttings associated withthe use of either water- or oil-baseddrilling fluids. These technologiesappear to be well-suited and efficient forthe reduction of oil content of suchwastes over a broad range ofhydrocarbon content.

There appear to be no insurmountabletechnical difficulties associated with theplacement of such equipment at offshoredrilling sites, operation of theequipment, intermediate handling of rawcuttings wastes to be processed, andhandling of processed cuttings wastesand by-product streams. Thesetechnologies are effective in achievingsubstantial reduction in the amount ofhydrocarbons adhering to the drillcuttings. Specific levels of oil content indrill cuttings wastes processed by thesetechnologies are presented in latersections of this notice.

B. Drilling Fluids

Oil-Based Drilling Fluids. Thermaldistillation/oxidation and solventextraction technologies appear to besuitable for processing materials withvariable hydrocarbon content. Oil-baseddrilling fluids (i.e., invert emulsion) cantypically contain 30% or more oil byvolume (approx. 15% oil by weight). Thehigh oil content (and low water content)of oil-based fluids should result in highlyefficient removal and recovery of the oilby these technologies.

However, the existing BPTrequirement of "no discharge of free oil"effectively prohibits the discharge of oil-based drilling fluids to surface waters ofthe U.S. An oil content limitation for oil-based drilling fluids that is based uponthese technologies would be lessstringent than the effective prohibitionon the discharge of any of these wastesbased upon the BPT requirement of nodischarge of free oil. Because theAgency's interpretation of the CleanWater Act precludes the establishmentof BAT, BCT, or NSPS limitations thatare less stringent than BPT, it is notappropriate to consider such a limitationor standard that would allow adischarge of oil-based drilling fluids tosurface waters.

Water-Based Drilling Fluids. Water-based drilling fluids to which oil hasbeen added for lubricity or spottingpurposes or such drilling fluids thatcontain entrained formationhydrocarbons are subject to the existingBPT requirement of "no discharge of freeoil". However, the amount orconcentration of oil contained in water-based drilling fluids for any of thesereasons is at considerably lower levelsthat that in oil-based drilling fluids. Oillevels in such water-based drilling fluidstypically range from nil to about 5% byvolume (2.5% by weight). In many cases,water-based drilling fluids containing oilat levels in this range wpuld not exhibita visible sheen (BPT "no discharge offree oil") upon their discharge. Thisfollowing discussion applies to the use

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Federal Register / Vol. 53, No. 204. / Friday, October 21, 1988 / Proposed Rules

of thermal and soivent extractiontechnologies for treating such drillingfluids for the reduction of oil content.

Three major factors make the use ofthe technologies under considerationless practicable for treating water-baseddrilling fluids at an offshore drillingfacility than for treating drill cuttings.

First, for a given well, the volume ofdrilling fluids to be handled is muchgreater than the volume of drill cuttings.Depending upon the capacity andprocessing rate capability of thetreatment unit, the time to process wastedrilling fluid generated during thedrilling of a well could make itimpractical to conduct the treatmentoperation at the offshore facility due tospace restrictions for storing thematerial and extended timerequirements for treatment if temporarystorage of the raw wastes wasavailable.

Second, even assuming that the wastedrilling fluid generated during thedrilling of the well can be processedeffectively, there remains a substanial-volume of drilling fluid to be disposed atthe end of drilling. At the end of thedrilling period, when the bulk drillingfluid system is ready to be disposed of,there is suddenly a large volume ofdrilling fluid that needs to betemporarily stored for subsequentprocessing (1400 bbl in the model case).Space for storing drilling fluids on anoffshore oil facility is limited. Again, thelength of time required to process thelarge volume of drilling fluids at the endof drilling may make it infeasible tostore the drilling fluids on an offshoredrilling facility prior to processing.

Third, in the case of the thermaltechnologies, the much higher relativewater content of water-based drillingfluids requires a considerably higherinput of thermal energy to the process inorder to vaporize the water present.(The water must be vaporized in orderto remove the oil). This directlyincreases the costs for treating thedrilling fluid. In cases where the thermalprocess is operating at or near itsmaximum capacity, the high energyrequirement (per unit of waste treated)may mean that the rate at which thedrilling fluids can be processed will besubstantially reduced. This in turnwould require increased storagecapacity for temporary onsite storage ofthe raw waste prior to treatment. (Thisfactor would be of negligibleconsideration for the land-basedthermal oxidation technology.)

One alternative might be to transportthe bulk drilling fluid system to shore forsubsequent treatment by one of thetechnologies under discussion.However,'the cost for transportation to

shore for processing would addconsiderably to the total cost oftreatment. It may also require either theexpense of duplicate equipment onshore to process the bulk mud system orelse the cost and disruption associatedwith relocation of the processingequipment from the offshore facility toshore. This additional expense couldmake the use of these technologies fortreating the drilling fluid less attractiveto industry than, for example, landdisposal.V. Pollutant Reduction and CostEstimates

The Agency has evaluated thetechnological feasibility and costs ofapplying thermal technologies andsolvent extraction technologies to: (1)Drill cuttings associated with oil-baseddrilling fluids; (2) drill cuttingsassociated with water-based drillingfluids which contain oil that has beenadded for lubricity purposes, spottingpurposes, or which contain entrainedformation hydrocarbons; and (3) water-based drilling fluids to which oil hasbeen added for lubricity purposes,spotting purposes, or which containformation hydrocarbons. :

This third scenario was evaluted toobtain estimates of increased energyrequirements and processing time fortreating water-based drilling fluids witha high water content. As discussedearlier, the Agency concluded from thisanalysis that the thermal distillation andsolvent extraction technologies underconsideration may not be appropriate asa basis for an oil content limitation forwater-based drilling fluids at anoffshore drilling site.

A. Pollutant Reduction Estimates

This subsection presents a summaryof the model drilling scenario which isthen used to establish estimates of oilcontent reduction in drill cuttings andwater-based drilling fluids wastes bythe technologies described earlier in thispart of today's notice. Then the resultantoil content reduction estimates arepresented for drill cuttings and waterbased-drilling fluids. Although theAgency has tentatively concluded thatthe reduction of oil content in water-based drilling fluids may be impractical -to implement at offshore drilling sites bythese technologies, oil content reductionestimates are presented below toprovide the reader with an indication ofthe potential of the technologies fortreating such wastes.

The Agency's analyses of applyingthermal processes and solventextraction processes are based on amodel 10,000 foot well in the Gulf of

Mexico, as presented in Section II ofPart 1 of today's notice.

Drilling a "typical" 10,000 foot well isestimated to take 35 calendar days with20 days of actual drilling time. Thevolume of drilling fluid to be handledfrom a 10,000 foot model well is 5349barrels plus an additional 1400 barrelactive mud system. The volume of drillcuttings to be handled from the 10,000foot model well is 1430 barrels. Thesemodel well characteristics used in theseanalyses are based on the Agency'sevaluation of recent industry surveys.(Sources: 10,000 ft. model we11,-"1984Joint Association Survey on DrillingCosts", Dec 1985, API; Drilling wastevolumes and drilling times-"AlternateDisposal Methods for Mud and Cuttings,Gulf of Mexico and Georges Bank:, Dec.1981, Offshore Operators Committee).

The untreated drill cuttings associatedwith oil-based drilling fluids areestimated to contain 20% oil by weight(approx. 55% oil by volume). Untreateddrill cuttings associated with water-based drilling fluid to which oil has beenadded, as a spot, as a lubricity agent orfrom entrained formation hydrocarbon,are estimated to contain 1% oil byweight (approx. 2.8% oil by volume).Water-based drilling fluids with oiladded for lubricity and spottingpurposes are estimated to typicallycontain 5% oil by volume (approx. 2.5%oil by weight) and 58% water by volume(approx. 30% water by weight). This 5%oil content by volume (approx. 2.5% oilby weight) is for a model situationwhere oil is added to the mud system forlubricity and spotting purposes, or ispresent due to entrained formationhydrocarbons. (Sources: EPA estimates;industry estimates)

After treatment, the oil content of thedrill cuttings from oil-based muds wasestimated to be reduced to 1% by weight(approx. 2.8% by volume) when usingthermal distillation and to 0.3% byweight (approx. 0.8% by volume] whenusing solvent extraction. (Sources: EPAand T-1, T-2 and SE vendor samplingdata.)

Since the oil content of untreated drillcuttings from water-based muds in themodel case is 1% (weight), there wouldbe little or no expected reduction of oilcontent in such wastes when subject tothermal distilation. The oil content ofdrill cuttings from water-based muds isestimated to be reduced to 0.3% byweight (approx. 0.8% by volume) whenusing solvent extraction technology.(Sources: EPA and T-1, T-2, and SEvendor sampling data).

After treatment, the oil content of thewater-based drilling fluids wasestimated'to be reduced to 1% by weight

141377,

I



(approx. 2% by volume) when using using solvent extraction (Sources: EPA The volumes and weights of oilthermal distillation and to 0.3% by estimates). present in the drilling wastes before andweight (approx. 0.5% by volume) when after treatment are shown on Table 5.

TABLE 5.-OIL CONTENT REDUCTION OF DRILLING WASTES BY VARIOUS TREATMENT PROCESSES

Total quantity of drilling Oil present before Oil removed

Waste type waste I treatment 2

bbls. lbs. bs. Ibs. bbls. lbs.

OIL-BASED Drill Cuttings (20% oil by weight) TD-1 & 2 Process Removal to1% by wgt ................................................................................................................. 1,430 1,330.000 792 266,000 752 252.000

OIL-BASED Drill Cuttings (20% oil by weight) SE Process Removal to .3% bywgt .............................................................................................................................. 1,430 1,330.000 792 266,00 780 261,500

WATER-BASED Drill Cuttings (1% oil by weight) TD-1 & 2 Process Removalto 1% by wgt ............................................................................................................. 1,430 1,330,000 40 13,300 0 0

WATER-BASED Drill Cuttings (1% oil by weight) SE Process Removal to .3%by wgt ......................................................................................................................... 1,430 1,330,000 40 13,300 28 700

WATER-BASED Drilling Fluid (5% oil by volume) TD-1 & 2 Process Removalto 1% wgt ............ ...................................... 5,349 3,584,000 267 113,400 161 54,000

WATER-BASED Drilling Fluid (5% oil by volume) SE Process Removal to.3% wgt ...................................................................................................................... 5,349 3,584,000 276 113,400 235 79,100

Sources: :"Alternate Disposal Methods for Mud and Cuttings Gulf of Mexico and Georges Bank", Dec. 1981, Offshore Operators Committee.

2 EPA Estimates.

b. Operating Costs

The Agency prepared treatment costestimates based of information providedby vendors and by using standingengineering estimating procedures.These estimates have been prepared fortwo types of distillation processes (T-1Process and T-2 Process) and for onesolvent extraction (SE-Process) processapplied to drill cuttings and water-baseddrilling fluids.

The costs for leasing and operatingthese treatment processes differ fromvendor to vendor. Two vendors had onelease rate for actual drilling days and alower rate for standby days. The othervendor had a fixed lease rate for bothdrilling and standby days.

A monetary value was assigned to theoil recovered by the treatment process.The model scenario assumes that all ofthe oil removed from the drilling wastesby a given treatment process will berecovered. However, in practice theamount of recovered oil will be less than100% of that removed from the wastes,due to losses by fugitive emissions,vapor condensation losses and oil/water separation efficiency fordistillation processes and due to solventrecovery efficiencies for the extractionprocess. This loss is assumed to besmall and not to significantly affect thecost of using a particular technology.The value of the recovered hydrocarbonis estimated to be $26.50 per barrel(source: vendor-supplied information).This full value of the recovered oil

would be realized only if the oil issuitable for reuse in drilling fluid. Whileit is reported that the recovered oil canbe reused in mud systems, the Agency isnot aware that this practice has beentested yet on a full-scale basis.-

The cost estimates include equipmentrental costs, personnel costs, energycosts, and transportation costs. Theequipment rental and energy costs arebased upon whether the unit is inoperating mode or standby mode. As anexample, a breakdown of the costestimate for treatment of drill cuttingsby one of the thermal distillationprocesses (T-1) operating for 20 daysand on standby for 15 days is shown inTable 6. In this example, the estimatedenergy cost is the cost of fuel for thegenerator used to provide electricalenergy to operate the treatmentequipment and to provide thermalenergy for processing the waste. (source:cost information from vendors, EPAestimates).

The cost presented in Table 6 weredeveloped with the conservativeassumption that four wells are drilledconsecutively. Mobilization anddemobilization costs for drilling multiplewells at a given site are allocated amongthe number of wells (in this case four)assumed to be drilled during a givencampaign. Thus, each well is allocatedonly a part of the total mobilization anddemobilization costs for the treatmentunit.

TABLE 6.-COMPONENT TREATMENT UNITLEASE AND OPERATING COSTS, THER-

MAL DISTILLATION (T-1 PROCESS)

[Drill cuttings. from oil-based or water-based drillingfluids]

Rental for 20 day actual operatingperiod ($4,000 per day) .......................... =$80,000

Rental for 15 day standby period($1,500 per day) ...................................... =22,500

Energy costs for unit during operation($180 per day, 20 days) ......................... =3,600

Personnel living on rig (2 menx35daysx $35 per day) ............................... =2,450

Transportation to rig (one boat for oneday)* ........................................................ . 750

Set-up on rig (including use of crane)* =2,500Tear down (including crane use)* ............ =1,250Transportation to shore (one boat for

one day)*= ................................................ . 750Shore support ............................................ =3,000Transporting personnel to and from rig

weekly (5x$600) .................................... = 3,000

Total .................................................. 119,800

Note.-(1) Costs treating for drill cuttings assumethe unit will be operating for 20 days and on standbyfor 15 days.

(2) Costs marked * are based on mobilization anddemobilization costs being apportioned between 4wells drilled consecutively at the same facility.

(3). Cost of deck space usage is not included.Source: Vendor-supplied information; EPA esti-

mates.

The operating costs in Table 7 wereestimated in a similar manner for theother two processes being considered.

C. Drill Cuttings from Oil- and Water-Based Drilling Fluids

Cost estimates were developed for thetreatment of drill cuttings. The costs for

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leasing and operating two types ofthermal distillation units (T-1 and T-2)and the solvent extraction unit (SE) overa 35 day drilling period, includingauxiliary costs, were estimated. In thisscenario where the systems are used totreat only drill cuttings, it is assumedthat the unit will be operating onlyduring the 20 days of actual drilling. Theequipment lease and energy costs arecalculated accordingly. The costs foroperating these processes areessentially the same whether they areused to treat drill cuttings associatedwith oil-based drilling fluids or water-based drilling fluids. These costs aresummarized in Table 7.

As described previously, a value of$26.50 per barrel is assigned to the oilrecovered by the treatment processassuming recovered oil is suitable for

reuse in the drilling fluid system. Thesecosting examples include theassumption that all of the oil removedfrom the drilling wastes is recovered forreuse.

Oil-Based Cuttings.

The drill cuttings from an oil-basedmud are estimated to have a 20% oilcontent by weight (approx. 55% byvolume); the volume of oil on thecuttings would therefore be 792 barrels.The volume of oil remaining on the

* cuttings after treatment by thermaldistillation to reduce the oil content to1% by weight (approx. 2.8% by volume)would be 40 barrels. The value of therecovered oil would therefore be $19,900(752 bblx$26.50). The volume of oilremaining on the cuttings aftertreatment by solvent extraction when

reducing the oil content to 0.3% byweight (approx. 0.8% by volume) wouldbe 12 barrels. The value of the recoveredoil would therefore be $20,700 (780bblx$26.50). Water-based Cuttings.

The cuttings from a water-based mudare extimated to have a 1% oil contentby weight (approx. 2.8% by volume) andthe volume of oil on the cuttings wouldtherefore be 40 barrels. There would belittle, if any, expected reduction in oilcontent where these wastes aresubjected to treatment by thermaldistillation. The volume of oil remainingon the cuttings after treatment bysolvent extraction when reducing the oilcontent to 0.3% by weight (approx. 0.8%by volume) would be 12 barrels. Thevalue of the recovered oil wouldtherefore be $740 (28 bblx$26.50).

TABLE 7.---COSTS OF TREATMENT FOR DRILL CUTTINGS 1

Thermal distrillation TD-1 process Thermal distrillation TD-2 Process Solvent extraction SE processProcedure Cost/unit Unit No. Total cost Cost/unit Unit No. Total cost Cost/unit Unit No. Total cost

Cuttings From OH-Based Drilling FluidsRental-drilling .................................................. 4,000 Day 20. =$80,000 1,550 Day 20 ......... =$31,000 4,200 Day 20. $84,000Rental-no drill ............................................... 1,500 Day 15 =22,500 1,500 Day 15 .. =23,250 2,000 Day 15 .=30.000Energy cost ................................................ 180 Day 20 =3,600 180 Day 20 ....... = 3,600 Included Day 20 = 0Living cost ....................................................... 70 Day 35 =2.450 70 Day 35 =2,450 70 Day 35 =2,450Transto rig ........................................................ 750 Each 1 750 750 Each 1 =750 750 Each 1 750Rig set-up ........................................................... 2,500 Each 1 .2,500 2,500 Each 1 = 2.500 2,500 Each 1 =2,500Rig tear-down .................................................. 1,250 Each 1 =1.250 1,250 Each 1 = 1.250 1,250 Each 1 =1.250Shore support. ........................................... 3,000 Each 1= 3,000 3,000 Each 1 =........ . 3,000 3,000 Each 1 =3.000Trans. to shore .................................................. 750 Each 1 = 750 750 Each 1. =750 750 Each 1 ........ = 750Weekly Trans ..................................................... 600 Each 5 ........ . =3,000 600 Each 5 .......... =3,000 600 Each 5 ........ . 3,000

Total ...................................................................................................... . 119,800 ........... : .................................. 71,550 ............................................... 127,700FOR OIL BASED DRILLING FLuID

1,430 bbs drill cuttings treated:Cost of treatment ...................-............................................................. = 119,800 ............................................. 71,550. .............................................. 127,700Cost of treatm ent per barrel .................... .............................................. . 84 ............................................. 50 ............................................... 89Value of recovered oil ............................................................................ = 19,900 .......................................... 19,900 ............................................. 20,600N et cost of treatm ent ............................................................................... . 99,900 ............................................. 51,650 ............................................... 107,100Net cost of treatment per barrel .......................... ............... . 70 ............................................. 36 ............................................... 75Cost of onshore disposal ........ . . . . . . . . =6,400....................... 66.400 .............................................. 66,400Onshore disposal cost 2 per barrel ...................................................... . =46 .............................................. 46 ............................................. 46

All three treatment units are assumed to take 20 days to process 1,430 barrels of drill cuttings.2 Onshore disposal costs assume rigs are retrofitted for cuttings storage.

D. Water-Based Drilling Fluids

Cost estimates were prepared for thetreatment of water-based drilling fluidsin order to assess increased energycosts and processing times for thetreatment of drilling fluids as comparedto drill cuttings. (The factors which maymake the use of this technology to treatwater-based fluids at an offshore oilfacility less practicable than for treatingdrill cuttings are described in Section Vof this part of today's notice.)

The costs of renting and operating thethermal distillation unit and the solventextraction unit over a 35 day drillingperiod, including auxiliary costs, wereestimated. It was assumed that in orderto treat the larger volume of drilling

fluids the unit will be required toprocess drilling fluids every day duringthe entire 35 day drilling period. Theequipment rental and energy costs werecalculated accordingly.

The average oil content of water-based drilling fluid is estimated to be 5%oil by volume (approx. 2.5% by weight),when oil is added to the mud either as aspotting fluid, a lubricity agent, and/orcontains entrained formation oil. Thevolume of oil in the 5349 barrels ofdrilling fluid (not including the activemud system) to be treated wouldtherefore be 267 barrels. The volume ofoil remaining on the drilling fluids, aftertreatment by thermal distillation whenreducing the oil content to 1% by weight(approx. 2% by-volume), is 107 barrels.

The value of the recovered oil wouldtherefore be $4300 (160 bblx $26.50). Thevolume of oil remaining on the drillingfluids after treatment by solventextraction when reducing the oil contentto 0.3% by weight (approx. 0.6% byvolume) is 32 barrels. The value of therecovered oil would therefore be $6,200(235 bbl X $26.50).

E. Comparison of Onsite TreatmentCosts with Onshore Disposal Costs forDrilling Wastes

The detailed costs are presented inthe EPA report titled "Costs, EnergyRequirements and Processing Rates forTreating Drilling Fluids and DrillCuttings using Thermal Distillation andSolvent and Solvent Extraction

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Processes" which is available in therecord of this rulemaking. These costsare summarized on a "per barrel of rawwaste" basis in Table 8 below and arecompared with transport to shore andland disposal costs of the wastes. Thethermal distillation and solventextraction technology costs in Table 8include a credit for recovered oil at anestimated economic value of $26.50 perbarrel of oil.

The transport/land disposal optioncosts are presented for three scenarios.These three scenarios are presented onthe basis of the ability to store thewastes during high seas or offload thesewastes for transport to shore as follows:

1. For rigs with no storage space fordrilling wastes, but designed for loadingboats in seas with wave heights of up to6 feet. If wave heights exceeded 6 feet,drilling would have to cease for theperiod that the wave heights were inexcess of 6 feet and supply boats wereunable to tie up at the facility.

2. For rigs with no storage space fordrilling wastes, but designed for loadingboats in seas with wave heights of up to10 feet. If wave heights exceeded 10 feet,drilling would have to cease for theperiod that the wave heights were inexcess of 10 feet and supply boats wereunable to tie up at the facility.

3. For rigs retrofitted for drillingwastes storage. These rigs couldcontinue to drill even when supply boatswere unable to tie-up at the facility.

The costs for land disposal in Table 8include onshore disposal costs, handlingcosts, container rental costs,transportation costs, and downtimecosts for rigs with no storage space orretrofit costs for rigs fitted with storagespace. Capital costs associated withretrofitting an offshore rig with sufficientstorage capacity and deck space toaccommodate storage of drilling wasteswere estimated. These retrofit costswere apportioned among the estimatednumber of wells drilled from a rig duringa 5-year estimated life of the rigequipment. These scenarios are basedupon prior industry-sponsored worksubmitted during the proposed commentperiod. The Agency has reviewed theindustry study documentation and foundthe information to be reasonable for thepurpose of establishing these scenarios.(Source: "Water-Based Drilling Fluidsand Cuttings Disposal Options Survey",Feb. 1986, Walk Haydel andAssociates).

The transportation costs were basedupon daily rental costs for supply boats.These costs were not sensitive to thedistance between the offshore facility

and the onshore transfer facility anddisposal site. The rigs with no storagecapacity were assumed to require twodedicated supply boats throughout theentire 35 day drilling period. The rigsretrofitted with storage capacity wereassumed to require two dedicatedsupply boats for the first 18 days of thedrilling period and one dedicated supplyboat for the remaining 17 days of thedrilling period. (source: "Water-BasedDrilling Fluids and Cuttings DisposalOption Survey", Feb. 1986, Walk Haydeland Associates).

The inajority of operators would, in allprobability, decide to retrofit rigs fordrilling fluid storage since this wouldresult in an overall lower cost for thedisposal of drilling fluids. (source:"Water-Based Drilling Fluids andCuttings Disposal Option Survey", Feb.1986 Walk Haydel and Associates). Thecosts are lowered because supply boatswould not be dedicated solely to drillingwaste disposal. It was thereforeestimated that 80% of the rigs would beretrofitted, 10% would operate using amaximum permissible wave height of 10feet and 10% would operate using amaximum permissible wave height of 6feet. (EPA estimate).

TABLE 8.-COST OF ONSITE TREATMENT V. ONSHORE DISPOSAL DRILL CUTTINGS AND WATER-BASED DRILLING FLUIDS-THERMALDISTILLATION, SOLVENT EXTRACTION, ONSHORE DISPOSAL-MODEL 10,O00FOOT WELL

(Dollar per barrel]

Drill cuttings Drill cuttingsassociated associated Water-

with oil- with water- basedbased based drilling fluids

drilling fluids drilling fluids

Onsite treatment using thermal distillation T-1 process ......................................................................................................................Onsite treatment using thermal distillation T-2 process.; ....................................................................................................................Onsite treatment using solvent extraction SE process .................................................................................. ; ...................................Transport to shore for disposal--no storage, max. 6 ft. waves .......................................................................................................Transport to shore for disposal- no storage, max. 10 ft. waves .................................................................. .....................................Transport to shore for disposal-rig retrofitted for storage ............................................

No expected reduction in oil Content.

703675786146

321629584533

Notes to Table 8:(1) Costs are in dollars per barrel of raw

waste rounded to the nearest whole dollIr.(2) Costs for drill cuttings are based upon

handling 1430 bbl of drill cuttings from themodel size well. (1)

•(3) Costs for drilling fluids treatment bythremal and solvent extraction are basedupon handling 5349 bbl of water-baseddrilling fluids. This excludes the active mudsystem volume of 1400 bbl. It is uncertainwhether onsite treatment is feasible for theactive mud system (1400 bbl). (1/2)

(4) Costs for onsite treatment consist ofequipment rental costs, energy costs,personnel costs and mobilization anddemobilization costs.(3) ,

(5) Costs for onshore disposal consist ofland disposal costs, handling costs, containerrental costs, transportation costs and retrofitcosts for rigs fitted with storage space fordrilling wastes or downtime costs for rigswith no storage space. (4)

Sources:(1) "Alternate Disposal Methods for Mud

and Cuttings, Gulf of Mexico and GeorgesBank:, Dec. 1981, Offshore OperatorsCommittee).

(2) EPA estimate.(3) Vendor-supplied information; EPA

estimates.(4) "Water-Based Drilling Fluids and

Cuttings Disposal Option Survey"; Feb. 1986,Walk Haydel and Assoc.

VI. Performance Data

A. Field Sampling

During the period September 14 to 17,1987, the Agency performed sampling offeed, waste and by-product streamsassociated with a thermal distillationunit (T-1 process) that was operating inthe South Pass Block of the Gulf ofMexico. The thermal distillation unitwas used to process cuttings generatedfrom a well drilled at an offshore facilityin the Gulf of Mexico. Oil-based mudswere utilized at the well from a depth of4,900 feet to the bottom of the well at13,944 feet. The diameter of the hole was

41380



12.25 inches and the well was beingdrilled at a rate of 140 feet per hour.Only a portion of the drill cuttingsgenerated at this well were processedby the thermal distillation unit. Due tothe existing configuration of the rigcuttings collection system, the rawcuttings feed was composed only of thecuttings from the primary shale shaker.

The following waste and by-productstreams were generated by theparticular thermal distillation unit thatwas tested: processed cuttings,condensed hydrocarbon, condensedwater, air emissions. The processedcuttings were mixed with seawater andsluiced to discharge from the facility.The condensed vapors (oil/water) weredirected to an oil/water separator whichhad two discharge streams-acondensed hydrocarbon stream and acondensed water stream. The treatmentsystem also had a stack for airemissions.

Samples were collected by EPS fromthe test unit over a four day samplingperiod. Samples were taken of the rawcuttings, the processed cuttings and thecombined processed cuttings/seawaterstream. The oil content of both the rawcuttings feed and the processed cuttingswas analyzed using retort-gravimetricand soxhlet exrtaction methods. The oilcontent of the combined seawater/cuttings stream was analyzed prior todischarge, using the gravimetricextraction method. The raw cuttingsfeed and the processed cuttings wereanalyzed for metals, priority organics,

percentage solids and for ICR/RCRAcomponents (ICR tests are foringnitability, corrosivity and reactivity;RCRA is the Resource Conservation andRecovery Act). The combined treatedcuttings/seawater stream to bedischarged was analyzed for totalsuspended solids. Bioassay tests wereperformed on samples of the rawcuttings and the processed cuttings.Samples were also taken of thecondensed hydrocarbon and waterstreams. These samples were analyzedfor oil content using the gravimetricextraction method, and for priorityorganics. Samples of the condensedwater discharge stream were alsoanalyzed for total suspended solids.

Temperature measurements and pHreadings were taken of the selected rawwaste, treated waste and by-productstreams. Tests for settleable solids inthe raw cuttings, the condensed waterstream, the combined treated cuttings/seawater stream and in backgroundseawater were conducted at the facility.Air sampling of the thermal unitemissions was not possible due to theunavailability of air sampling personnelduring the sampling effort.

B. Observations and Sampling Results

During the sampling program, thevendor demonstrated the ability to setup and run a thermal distillation unit onan offshore development facility to treatdrill cuttings associated with oil-basedmuds.

The average oil content of the rawcuttings was found to be 7.11% by

weight using soxhlet extraction analysisand 5.82% by weight using the retort-gravimetric method. The raw cuttingswere considerably lower in oil contentthan expected for the type of mud beingused. This was probably because theonly source of cuttings used as feed tothe test unit was the primary shaleshaker. The cuttings from the primaryshale shaker are physically the largestcuttings in the entire cuttings recoverysystem. The smaller, finer cuttings fromthe secondary shaker, the desilter andthe contrifuge sections of the cuttingsrecovery system would have the higheroil content due to their higher surfacearea. A composite sample of all of thecuttings generated at the well would beexpected to have an oil content of 15%to 20% by weight (source: EPA estimate;Conoco, Inc. estimate).

The thermal distillation unit wasshown, when operating properly, to beable to consistently reduce the oilcontent of drill cuttings, separated froman oil-based mud at the primary shaleshaker, to less than 1% by weight (lessthan 2.8% by volume). The processedcuttings were dry and granular inappearance. The results from thesampling episode therefore indicate thatthe thermal distillation unit tested couldachieve a significant reduction in the oilcontent of drill cuttings.

The results of oil analyses of samplesof raw and treated wastes and by-product streams are presented in Table9.

TABLE 9.-THERMAL DISTILLATION OF DRILL CUTTINGS (OIL-BASED MUD), AVERAGE OIL CONTENT, PERCENT BY WEIGHT

Soxhlet method Retort-gravimetric method Gravimetric method 3

Raw cuttings......................................................................................... 7.11 ................................................. 5.82 .................................. ...... ... Not appr.Proc. cuttings ........................................................................................ 0.06 ................................................. 0.53 ................................................ Not appr.Combined seawater/cuttings .............................................................. Not appr ......................................... Not appr .......................................... 0.06.Condensed hydrocarbons ................................................................... Not ppr. .................. Not appr .......................................... 97.4.Condensed water .................................................................... Not ppr.......... ................ .** * Not appr ........................................ 0.06.Sea w ater ................................................ , ............................................. INot appr. ......................................... IN ot appr .................... ..................... 10.00 3.

Notes:"Not Appr." indicates that a particular analytical method was not an appropriate analytical method for type of waste stream sampled.I Method 503D, Oil & Grease, Extraction Method for Sludge Samples. Standard Method for the Examination of Water and Wastewaters; APHA, AWWA, WPCF;

16th Edition, 1985.2Proposed Method 1651, Total Oil and Diesel Oil in Drilling Fluids and Drill Cuttings by Retort Gravimetry and GCFID. Appendix A of this notice. This is the

Agency's preferred method for oil content determinations for drilling wastes with relatively high solids content.3

Method 413.1, Oil & Grease, Gravimetric (extraction). Methods for Chemical Analysis of Water and Waste, EPA-600/4-79-020, U.S. EPA, March 1979.

Acute toxicity was measured byconducting static, 96-hour toxicity testswith mysids on the suspendedparticulate phase (SPP) of raw andprocessed drill cuttings. The SPP wasprepared by mixing the drill cuttingswith seawater (1:9 by volume), allowingthe mixture to settle for 1 hour, anddecanting the SPP. Three subsamples ofone sample of raw cuttings were tested.The 96-hour LC50s were 3.2%, 8.5% and

1.5% SPP. Two samples of processedcuttings were tested; the 96-hour LC50swere 28.7% and 27.9% SPP.

Samples of the raw cuttings,processed cuttings, condensedhydrocarbons and condensed waterwere analyzed for organics. A total often (10) samples-one raw cuttings, fourprocessed cuttings, one condensedhydrocarbon and four condensed

water-were each analyzed for twohundred and thirty-four (234) organics.

Twenty-eight organic compoundswere detected at concentrations abovetheir detection limits in some or all ofthe samples. The remaining two hundredsix organics compounds were either notdetected or were quantified at a levelbelow the method detection limit.

Detailed discussion and results of thissampling program are presented in the

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EPA document titled "Report on theResults of Field Sampling or ThermalDynamics Inc. Treatment of DrillCuttings on Conoco South Pass 75Platform September 14-17th, 1987". Thisreport is part of the record of thisrulemaking and is available forinspection as described in the"addresses" section of this notice.

VII. Oil Content or Untreated DrillingWastes

This section presents a summary ofthe Agency's estimates of the quantitiesof untreated drill cuttings and water-based drilling fluids that would not meetan oil content effluent limitation of 1% orless (weight basis). These estimatedquantities of drilling wastes wouldeither require treatment to comply withan oil content limitation or,alternatively, the wastes could bedisposed of in another manner such asby transport to shore for land disposalat an acceptable waste disposal site.

A. Drill Cuttings

Oil-Based Cuttings. All drill cuttingsassociated with oil-based drilling fluidswould require treatment or landdisposal to comply with an oil contentlimitation of 1% or less (weight basis).Water-based Cuttings.

Based upon the waste characteristicsdescribed above for the model situation,little if any of drill cuttings associatedwith water-based drilling fluids whichcontain oil added either as a lubricityagent or as a spotting fluid would likelyrequire treatment to comply with an oilcontent limitation.

Some portion of drill cuttingsassociated with water-based drillingfluids to which no oil has been added(lubricity, spotting) may requiretreatment or land disposal to complywith an oil content limitation. Thiswould be due to entrained formation oilsin the drilling fluid system which in turncould adhere to the drill cuttings wastes.The Agency has no estimate of drillingwaste volumes that would fall into thisscenario (drilling wastes or drillcuttings]. For the purposes of thisanalysis, the Agency assumed a zeroquantity of drilling wastes in thisscenario. The Agency solicits specificinformation which would allow for areasonable estimate to be made of thesedrilling waste volumes.

The results of an industry surveyindicate that approximately 12% of allwells drilled with water-based mudshave oil added to the mud system forlubricity purposes. (source: Shell Oil,Burgbacher, 1985). As discussedpreviously, the drill cuttings generatedunder these circumstances are estimatedto contain 1% oil by weight. (EPA

estimate). For this analysis then, most ifnot all drill cuttings from wells drilledwith water-based muds are estimated tohave a oil content of 1% by weight andthus would not require treatment or landdisposal to meet an oil contentlimitation of 1% by weight.

In summary, drill cuttings from water-based muds to which (mineral) oil hasbeen added for lubricity and/or spottingpurposes would likely not requiretreatment or land disposal to complywith an oil content limitation of 1% byweight.

B. Water-Based Drilling FluidsWater-based drilling fluids which

contain oil added either as a lubricityagent or as a spotting fluid, orcontaining formation hydrocarbons inappreciable amounts would likelyrequire treatment to comply with an oilcontent limitation in the range of 1% orless (weight basis).

Historical information supplied by theindustry indicates that approximately12% of all wells drilled with water-basedmuds can be expected to use oil as alubricity agent (source: API). Theamount of lubricity oil used varies fromabout 1% to 12% (volume basis), with anestimated average of 3%. This, alldrillings fluids generated from suchwells would require either treatment toreduce the oil content prior to dischargeor transport to shore for land disposal tocomply with an oil content limitation.(Source: 1986 API Drilling FluidsSurvey.)

The results of a recent surveyconducted by the Offshore OperatorsCommittee indicate that approximately22% of wells drilled with water-basedmuds can be expected to use oil as aspotting fluid (1986 Offshore OperatorsCommittee Spotting Fluid Survey).Water-based drilling fluid to which oil isadded as a spotting fluid at depthsbelow 8,000 feet would likely contain oilin excess of 1% by weight, and thuswould either have to be processed forremoval of oil and then discharged ortransported to shore for disposal. (TheEPA model case use of oil added as aspotting fluid below a depth of 8,000 feetwas estimated for model wellcharacteristics.)

The total volume of drilling fluid to behandled from a 10,000 foot well isestimated to be 6749 barrels (includingthe active mud system), of whichapproximately 2076 barrels (includingthe active mud system) are generatedbetween 8,000 feet and 10,000 feet(source: "Alternate Disposal Methodsfor Mud and Cutting for the Gulf ofMexico and Georges Bank", Dec. 1981,Offshore Operators Committee). Thus,the percentage of all water-based

drilling fluids used which would containoil as a spotting fluid is estimated to be6.8% (22% x 2076 bbl/6749 bbl),

Assuming, conservatively foraggregate costing purposes, .that there isno overlap in the population of wellsusing oil as a lubricity agent and thoseusing oil as a spotting fluid, anestimated total of 18.8% by volume of allwater-based drilling fluids wouldrequire onsite treatment of onshoredisposal to comply with an oil contentlimitation as discussed above.

VIII. Analytical Method for Total OilContent

A method for retort distillation andgravimetry for determining the total oilcontent of drilling fluid and drill cuttingswaste streams is published as part oftoday's notice for review and comment.The Agency has determined thatexisting approved analytical methodsfor measuring oil are not appropriate fordrilling wastes and that the oil contentmethod appearing in Appendix A of thisnotice is the appropriate test procedure.

This same method (Proposed Method1651, "Total Oil and Diesel Oil inDrilling Muds and Drill Cuttings byRetort Gravimetry and GCFID")includes additional steps fordetermining the identity andconcentration of diesel oil, and ispresented in its entirety in Appendix Aof this notice.

The retort distillation method hasbeen widely used by the industry fortesting drilling muds and is simple toperform on offshore facilities in remoteconditions. The version of the methodpresented in Appendix A has anestimated detection limit of 200 mg/kg(0.02% by weight). Documentation onprecision-and accuracy measurements ofthe test method is included in the recordfor this rulemaking.

IX. Requst for Comments

As previously stated, the Agency isconsidering a BAT and NSPS oil contentlimitation of up to 1.0% by weight fordrill cuttings associated with either oil-based or water-based drilling fluids.Such a limitation may be based uponattainable performance of the controland treatment technologies discussed inthis notice and prior notices pertainingto this rulemaking. The Agency solicitscomment on all aspects of such a BATand NSPs oil content limitation forcontrol of priority and toxic non-conventional pollutants in thehydrocarbons present in drill cuttings.This limitation would apply to all drillcuttings discharges to surface waters,whether or not oil is added't6 theassociated drilling fluid system.

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Moreover, for cuttings asssociated withoil-based muds, this oil contentlimitation would replace the prohibitionon the discharge of such cuttings. TheAgency particularly solicits commenton: (1) Whether such an oil contentlimitation is appropriate for drillcuttings; (2) the appropriate technologybasis for an oil content limitation; and(3) whether an oil content limitationshould apply in addition to or instead ofone or more of the other limitations andstandards for drill cuttings presented inPart I of this notice.

The Agency also invites comment onall aspects of establishing BAT andNSPS oil content limitations for water-based drilling fluids. The Agencyparticularly solicits comment on thepracticality and technical achievabilityof processing water-based drilling fluidsby these technologies at offshore drillingsites and on the issue of spaceconstraints with regard to installingthese systems at offshore facilities.

The Agency solicits comment on themodel drilling scenarios selected foranalysis, the costs to implement thetreatment technologies and treatmentmethods discussed in this part, and onany actual and foreseeable problemsregarding adequate onshore disposalsites for drilling wastes. The Agencyalso invites comment on the extent towhich the oil content and the toxicity ofdrill cuttings and drilling fluids is due todownhole contamination. The Agencyalso invites comment on theapplicability of these technologies todrilling wastes from Alaskan coastaland offshore facilities.

Some of the technologies discussed inthis part of today's notice have airemissions associated with the operationof the processes. The Agency hasobtained some air emissionscharacterization data on thesetechnologies, but does not havesufficient information to properlyconsider the non-water quality aspectsof these technologies. The Agencysolicits additional emissionscharacterization data from the operationof these technologies.

As indicated by the analytical methodfor oil content determinations presentedin Appendix A of today's notice, theAgency's preferred method for oilcontent determinations for wastescontaining high solids content (i.e., drillcuttings, drilling fluids) is the "retort-gravimetric" method. The Agencyrequests that any commenters thatintend to supply the Agency withperformance data on drilling fluid ordrill cuttings treatment technologiesprovide oil content determinationsbased upon the retort-gravimetricmethod presented in Appendix A below.

Appendix A-Proposed Method 1651-Oil Content and Diesel Oil in DrillingMuds and Drill Cuttings by RetortGravimetry and GCFID

1 Scope and Application1.1 This method is used to determine

the oil content and the identity andconcentration of diesel oil in drillingfluid (mud) samples. It is applicableto all mud types and may also beused to determine the oil contentand diesel oil in drill cuttings.

1.2 This method may be used forcompliance monitoring purposes aspart of the "Effluent LimitationsGuidelines and New SourcePerformance Standards for theOffshore Subcategory of the Oil andGas Extraction Point SourceCategory".

1.3 When this method is used toanalyze samples for which there isno reference diesel oil, diesel oilidentification should be supportedby at least one additionalqualitative technique. Methods 625and 1625 provide gaschromatograph/mass spectrometer(GC-MS) conditions appropriate forthe qualitative and quantitativeconfirmation of the presence of thecomponents of diesel oil (references1-2).

1.4 The detection limit of this methodis usually dependent upon thepresence of other oils in the sample.Excluding interferences, estimateddetection limits of 200 mg/kg of oilcontent and 100 mg/kg of diesel oilcan be obtained.

1.5 Any modification of this methodbeyond those expressly permittedshall be considered as a majormodification subject to applicationand approval of alternate testprocedures under 40 CFR 136.4 and136.5.

1.6 The gas chromatography portionsof this method are restricted to useby or under the supervision ofanalysts experienced in the use ofgas chromatograms. Eachlaboratory that uses this methodmust generate acceptable resultsusing the procedures described insections 8.2 and 12 of this method.

2 Summary of Method2.1 A weighed amount of drilling mud

is distilled using a retort apparatus.The distillate is extracted withmethylene chloride and the extractis dried by passage through sodiumsulfate. The extract is evaporated todryness, and the total amount of oilis redissolved in methylenechloride, an internal standard isadded, and an aliquot is injectedinto a gas chromatograph (GC). The

components of the oil are separatedby the GC and detected using aflame ionization detector (FID).

2.2 Identification of diesel oil(qualitative analysis) is performedby comparing the pattern of GCpeaks (retention times andintensities) from the sample extractwith the pattern of GC peaks from areference diesel oil sample.Identification of diesel oil isestablished when the referencediesel and sample patterns agreeper the criteria in this method.

2.3 Quantitative analysis of diesel oilis performed using an internalstandard technique.

3 Contamination and Interferences3.1 Solvents, reagents, glassware and

other sample processing hardwaremay yield artifacts and/or elevatedbaselines causing misinterpretationof chromatograms. All materialshall be demonstrated to be freefrom interferences under theconditions of the analysis byrunning method blanks initially andwith set of samples. Specificselection of reagents andpurification of solvents bydistillation in all-glass systems maybe required. Glassware and, wherepossible, reagents are cleaned bysolvent rinse or baking at 450degree C for one hour minimum.

3.2 There is no standard diesel oil. Oilcomponents, as seen by GC-FID,will differ depending upon the oilsource, the production date,production process, and theproducer. In addition, there arethree basic types of diesel oils:ASTM Designations No. 1-D, No. 2-D, and No. 4-D. The No. 2-D is mostcommon "diesel oil"; however, No.2-D is sometimes blended with No.1-D which has a lower boilingrange. For rigorous identificationand quantification of diesel oil in adrilling fluid sample by GC-FID, thechromatographic pattern from thediesel oil should be matched withthe chromatographic pattern from areference standard of the samediesel oil suspected to be in thesample.

3.3 To aid in the identification ofinterferences, the chromatographicpattern from a reference sample ofdrilling fluid prior to use iscompared to the chromatographicpattern of the drilling fluid after use.An interference is present when thepattern of the background oil doesnot match, but contributessubstantially to, the pattern of thediesel oil in the sample.

II

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3.4 Mineral oils are often added todrilling fluids for lubricity. Theseoils when examined by GC-FID,contain some components commonto diesel oil but havechromatographic patterns that aredistinctly different from diesel oil.The analyst must first determine ifthe sample chromatogram showsthe presence of diesel, mineral, or acombination of both before reliablequantification can be performed.This method permits selection ofGC peaks unique to diesel oil fordetermination of diesel oil in thepresence of mineral oil.

4 Safety4.1 The toxicity or carcinogenicity of

each reagent used in this methodhas not been defined. Therefore,each chemical compound should betreated as a potential health hazard.From this viewpoint, exposure tothese chemicals must be reduced tothe lowest possible level bywhatever means available. Thelaboratory is responsible formaintaining a current awarenessfile of OSHA regulations regardingthe safe handling of the chemicalspecified in this method. Areference file of material handlingdata sheets should also be madeavailable to all personnel involvedin the chemical analysis. Additionalreferences to laboratory safety areavailable and have been identified(references 3-5) for the informationof the analyst.

4.2 Methylene chloride has beenclassified as a known healthhazard. All steps in this methodwhich involve exposure to thiscompound shall be performed in anOSHA approved fume hood.

5 Apparatus and Materials5.1 Sample bottles for discrete

sampling5.1.1 Bottle--4 oz Bosxton round wide

mouth jar with Teflon lined screwcap (Sargent Welsh S-9184-72CA,or equivalent). New bottles are usedas received with no further cleaningrequired.

5.1.2 Bottle mailer-to fit bottles above(Sargent-Welsh 2306, or equivalent).

5.2 Distillation Apparatus5.2.1 Retort-20 mL retort apparatus

(IMCO Services Model No. R2100 orequivalent).

5.2.2 Glass wool-Pyrex (Corning 3950,or equivalent). Solvent extracted orbaked at 450 degrees C for one hourminimum.

5.3 Extraction/drying apparatus5.3.1 Separatory funnel--60 mL with

Teflon stopcock5.3.2 Drying column-400 mm x 15 to

20 mm i.d. Pyrex chromatographic

column equipped with coarse glassfrit or glass wool plug.

5.3.3 Glass filtering funnel-crucibleholder (Coming No. 9480, orequivalent).

5.3.4 Spatulas-stainless steel orTeflon

5.4 Evaporation/concentrationapparatus

5.4.1 Kuderna-Danish (K-D) apparatus5.4.1.1 Evaporation flask-500 mL

(Kontes K-570001-0500, orequivalent), attached toconcerntrator tube with springs(Kontes K-662750-0012).

5.4.1.2 Concentrator tube-10 mL,graduated (Kontes K-570050-1025,or equivalent) with calibrationverified. Ground glass stopper (size19/22 joint) is used to preventevaporation of extracts.

5.4.1.3 Snyder column-three ballmacro (Kontes K-503000-0232, orequivalent).

5.4.1.4 Snyder column-two ball micro(Kontes K-469002-0219, orequivalent).

5.4.1.5 Boiling chips5.4.1.5.1 Glass or silicon carbide-

approx 10/40 mesh, extracted withmethylene chloride and baked at450 degrees C for one hr minimum.

5.4.1.5.2 Teflon {optional)-extractedwith methylene chloride.

5.4.2 Water bath-heated, withconcentric ring cover, capable oftemperature control (+/- 2degrees C), installed in a fume hood.

5.4.2 Sample vials-amber glass, 1 - 5mL with Teflon-lined screw orcrimp cap, to fit GC autosampler.

5.5 Balances5.5.1 Analytical-capable of weighing

0.1 mg. Calibration must be verifiedwith class S weights each day ofuse.

5.5.2 Top loading-capable of weighing10 Mg.

5.6 Gas Chromatograph (GC)-analytical system with splitinjection, capillary column,temperature program with initialand final isothermal holds, and allrequired accessories includingsyringes, analytical columns, gases,detector, and recorder. Theanalytical system shall meet theperformance specifications insection 12.

5.6.1 Column-30 +/-5m X 0.25 +/- 0.02 mm i.d., 99% methyl, 1%vinyl, 1.0 um film thickness, bondedphase fused silica capillary(Supelco SPB-1, or equivalent).

5.6.2 Detector-flame ionization. Thisdetector has proven effective in theanalyses of drilling fluids for dieseloil, and was used to develop themethod performance statements in

section 16. Guidelines for usingalternate detectors are provided insection 11.1.

5.7 GC Data system-shall collect andrecord GC data, store GC runs inmagnetic memory or on magneticdisk or tape, process GC data,compute peak areas, storecalibration data including retentiontimes and response factors, identifyGC peaks through retention times,and compute concentrations

5.7.1 Data acquisition-GC data shallbe collected continuouslythroughout the analysis and storedon a mass storage device.

5.7.2 Response factors and calibrationcurves-the data system shall beused to record and maintain lists ofresponse factors, and multi-pointcalibration curves (section 7).Computations of relative standarddeviation (coefficient of variation;CV) are used for testing calibrationlinearity. Statistics on initial(section 8.2) and on-going (section12.5] performance shall becomputed and maintained.

5.7.3 Data processing-the data systemshall be used to search, locate,identify, and quantify thecompounds of interest in each GCanalysis. Software routines shall beemployed to compute and recordretention times and peak areas.Displays of chromatograms andlibrary comparisons are required toverify results.

6 Reagents6.1 Sodium sulfate-anhydrous, (ACS)

granular.6.2 Methylene chloride-Nanograde or

equivalent.6.3 Reagent water-water in which the

compounds of interest andinterfering compounds are notdetected by this method.

6.4 Internal standard-dissolve 1.0 g of1,3,5-Trichlorobenzene (Kodak No.1801 or equivalent) in 100 mLmethylene chloride. Store in glassand tightly cap with Teflon lined lidto prevent loss of solvent byevaporation. Label with theconcentration and date. Mark thelevel of the meniscus on the bottleto dtect solvent loss.

6.5 Calibration standards-calibrationstandards are prepared from thesame diesel oil expected to be in thesample; otherwise, No. 2 diesel oil isused. Calibration standards areprepared at the concentrationsshown in table 1.

6.5.1 Weigh the appropriate amount ofoil into a tared 10 mL volumetricflask and dilute to volume withmethylene chloride. Calibration

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standards are made fresh daily toavoid solvent loss by evaporation.

6.5.2 Using a micropipet ormicrosyringe, transfer 100 uL ofeach reference standard solution(Section 6.5.1) to a GC injection vial.Add 100 uL of the TCB internalstandard (6.4) to each vial and mixthoroughly.

6.6 QC standard-used for tests ofinitial (section 8.2) and ongoing(section 12.5) performance. Areference drilling fluid known tocontain 10,000-50,000 mg/kg ofdiesel oil is used, if available. If areference drilling fluid is notavailable, a solution containing 600mg/mL of No. 2 diesel oil inmethylene chloride is used.

7 Calibration7.1 Establish gas chromatographic

operating conditions given in Table2. Verify that the GC meets theperformance criteria in section 12and that the EDL given in section1.4 can be achieved. The gaschromatographic system iscalibrated using the internalstandard technique.

7.2 Internal standard calibrationprocedure-1,3,5-Trichlorobenzene(TCB) has been shown to be free ofinterferences from the diesel oilstested in the development of thismethod. However, if an interferenceis known or suspected, the analystmust choose an alternate internalstandard that is free frominterferences.

7.2.1 Inject 1 uL of each reference oilstandard containing the internalstandard (table 1 and section 6.5.2)into the GC-FID. The TCB will eluteapprox. 8.5 minutes after injection.For the CG-FID used in thedevelopment of this method, theTCB internal standard peak was 30-50 percent of full scale at anattenuator setting of 813-11 amp.

7.2.2 Individual response factors7.2.2.1 Tabulate the peak area

responses against concentration foreach n-alkane peak listed in table 3and for the internal standard.Calculate response factors (RF) for

each n-alkane peak using thefollowing equation:

Equation 1:(As) (Cis)RF-=(Ais) (Cs)

where:As=Area of the peak to be measured.Ais=Area of the internal standard peak.Cs =Concentration of the peak to be

measured (mg/kg).Cis= Concentration of the internal

standard (mg/kg).

7.2.2.2 If the RF is constant (<10% CV)over the calibration range (table 1),the RF can be assumed to beinvariant and the average RF can beused for calculations. Alternatively,the results can be used to plot acalibration curve of response ratios,As/Ais, vs RF.

7.2.2.3 Calibration verification-theaverage RF or a point on thecalibration curve shall be verifiedon each working day by themeasurement of one or morecalibration standards. If the RF forany peak varies from the RFobtained in the calibration by morethan +/- 15 percent, the test shallbe repeated using a freshcalibration standard. Alternatively,a new calibration curve shall beprepared.

7.2.3 Combined response factor-toreduce the error associated with themeasurement of a single n-alkanepeak, a combined response factor isused for computation of the dieseloil concentration. This combinedresponse factor is the sum ofindividual response factors as givenin equations 2 or 3:

Equation 2:

RFcombined

[RF(1)+RF(2). . .+RF(n)] (Cis)

Equation* 3:

RFcombined

[As(l)+As(2) * * *+As(ni) (Cis)

(Aisl) (Cs)where:

As(i) *A(n) are the areas of theindividual peaks.

8. Quality assurance/quality control.8.1 Each laboratory that uses this

method is required to operate aformal quality assurance program(reference 6). The minimumrequirements of this programconsist of an initial demonstrationof laboratory capability, an ongoinganalysis of standards and blanks asa test of continued performance,analyses of spiked samples toassess accuracy, and analysis ofduplicates to assess precision.Laboratory performance iscompared to establishedperformance criteria to determine ifthe results of analyses meet theperformance characteristics of themethod.

8.1.1 The analyst shall make an initialdemonstration of the ability togenerate acceptable accuracy andprecision with this method. Thisability is established as describedin section 8.2.

8.1.2 The analyst is permitted tomodify this method to improveseparations or lower the costs ofmeasurements, provided allperformance requirements are met.Each time a modification is made tothe method, the analyst is requiredto achieve the EDL (section 1.4) andto repeat the procedure in section8.2 to demonstrate methodperformance.

8.1.3 Analyses of blanks are requiredto demonstrate freedom fromcontamination. The procedures andcriteria for analysis of a blank aredescribed in section 8.5.

8.1.4 The laboratory shall, on an on-going basis, demonstrate throughcalibration verification and theanalysis of the QC standard(section 6.6) that the analysissystem is in control. Theseprocedures are described in section12.

8.1.5 The laboratory shall maintainrecords to define the quality of datathat is generated. Development of

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accuracy statements is described insections 8.3.4 and 12.5.

8.2 Initial precision and accuracy-toestablish the ability to generateacceptable precision and accuracy,the analyst shall perform thefollowing operations:

8.2.1 Retort, extract, concentrate, andanalyze four samples of the QCstandard (section 6.6 and 10.1.3)according to the procedurebeginning in section 10.

8.22 Using results of the set of fouranalyses. compute the averagerecovery (X) in mg/kg and thestandard deviation of the recovery(s) in mg/kg for each sample by theinternal standard method (sections7.2 and 14.2).

8.2.3 For each compound, compare sand X with the corresponding limitsfor initial precision and accuracy intable 4. If s and X meet theacceptance criteria, systemperformance is acceptable andanalysis of samples may begin. Ifhowever. s exceeds the precisionlimit or X falls outside the range foraccuracy, system performance isunacceptable In this event, correctthe problem, and repeat the test.

8.3 Method accuracy-the laboratoryshall spike a minimum of 20 percentlone sample in each set of fivesamples) of all drilling fluidsamples. This sample shall bespiked with the diesel oil that wasadded to the drilling fluid. If areference standard of diesel oil thatwas added to the drilling fluid is notavailable. No. 2 diesel oil shall beused for this spike. If doubt of theidentity and concentration of dieseloil in any of the remaining 80percent of the samples exists, thatsample shall be spiked to confirmthe identity and establish the dieseloil concentration.

8.3.1 The concentration of the spike inthe sample shall be determined asfollows:

8.3.1.1 If. as in compliance monitoring.the concentration of the oil in thesample is being checked against aregulatory concentration limit, thespike shall be at that limit or at oneto five times higher than thebackground concentrationdetermined in section 8.3.2,whichever concentration is larger.

8.3.1.2 If the concentration of the oil ina sample is not being checkedagainst a limit, the spike shall be atthe concentration of the QCstandard (section 6.6) or at one tofive times higher than thebackground concentration,

.whichever concentration is larger.8.3.2 Analyze one sample aliquot to

determine the backgroundconcentration (B) of oil content andof diesel oil. If necessary, prepare astandard solution appropriate toproduce a level in the sample at theregulatory concentration limit or atone to five times the backgroundconcentration (per section 8.3.1).Spike a second sample aliquot withthe standard solution and analyze itto determine the concentration afterspiking (A) of each analyte.Calculate the percent recovery (P)of oil content and of diesel oil:

P= too (A-B)/Twhere T is the true value of the spike.

8.3.3 Compare the percent recovery foroil content and for diesel oil withthe corresponding QC acceptancecriteria in table 4. If the results ofthe spike fail the acceptancecriteria, and the recovery of QCstandard in the on-going precisionand recovery test (sections 10.1.3and 12.5) is within the acceptancecriteria in table 4, an interferencemay be present (see sections 3 and15 for identification ofinterferences]. If. however, theresults of both the spike and the on-going precision and recovery testfail the acceptance criteria, theanalytical system is judged to beout of control and the problem mustbe immediately identified andcorrected, and the samplereanalyzed.

8.3.4 As part of the QA program for thelaboratory, method accuracy forsamples shall be assessed andrecords shall be maintained. Afterthe analysis of five spike samples inwhich the recovery passes the testin section 8.3, compute the averagepercent recovery (P) and thestandard deviation of the percentrecovery (sp). Express the accuracyassessment as a percent recoveryinterval from P-2sp to P + 2sp. Forexample, if P=90% and sp=10% forfive analyses of diesel oil, theaccuracy interval is expressed as70-110%. Update the accuracyassessment on a reqular basis (e.g.after each 5-10 new accuracymeasurements).

8..4 The laboratory shall analyzeduplicate samples for each drillingfluid type at a minimum of 20percent (one sample for each fivesample set). A duplicate sampleshall consist of a well-mixed,representative aliquot of thesample.

8.4.1 Analyze one sample in the set induplicate per the procedurebeinning in section 10.

8.4.2 Compute the relative percentdifference (RPD) between the tworesults per the following equation:

Equation 4:

RPD= (D1-D2) X100(Dl+D2)/2

where:D1=concentration of diesel in the sampleD2 = concentration of diesel oil in the

second (duplicate) sample

8.4.3 The relative percent difference forduplicates shall meet theacceptance criteria in table 5. If thecriteria are not met, the analyticalsystem shall be judged to be out ofcontrol, and the problem must beimmediately identified andcorrected, and the sample setreanalyzed.

8.5 Blanks-reagent water blanks areanalyzed to demonstrate freedomfrom contamination.

8.5.1 Extract and concentrate a reagentwater blank initially and with eachsample set (samples started throughthe analysis on the same day, to amaximum of 5 samples). Analyzethe blank immediately afteranalysis of the QC standard(section 6.6) to demonstrate freedomfrom contamination.

8.5.2 If any of the components of dieseloil or any potentially interferingcompound is detected in a blank,analysis of samples is halted untilthe source of contamination iseliminated and a blank shows noevidence of contamination.

8.6 Comparison of gravimetric anddiesel oil measurements.

8.6.1 Compare the concentration of theoil content (14.1.2) determinedgravimetrically with the diesel oilconcentration determined by GCFID(14.2.2). If the diesel oilconcentration exceeds thegravimetric oil concentration, theanalysis has been performedimproperly. Correct the error orrepeat the sample analysisbeginning with section 10.

8.7 The specifications contained in thismethod can be met if the apparatusused is calibrated properly, thenmaintained in a calibrated state.The standards used for calibration(section 6.4), calibration verification(section 7.3), and for initial (section8.2] and on-going (section 12.5)precision and recovery should be

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identical, so that the most preciseresults will be obtained. The GCinstrument will provide the mostreproducible results if dedicated tothe settings and conditions requiredfor the analyses of the analyte givenin this method.

8.8 Depending on specific programrequirements, field replicates andfield spikes of diesel oil intosamples may be required to assessthe precision and accuracy of thesampling and sample transportingtechniques.

9 Sample Collection, Preservation, andHandling

9.2 Collect samples in glass containersfollowing conventional samplingpractices (reference 7]. Drilling fluidsamples are collected in wide-mouth jars.

9.2 Samples must be representative ofthe entire bulk drilling fluid. In someinstances, composite samples maybe required.

9.3 Maintain samples at 0-4 degrees Cfrom the time of collection untilextraction.

9.4 Sample and extract holding timesfor this method have not yet beenestablished. However, based ontests of wastewater for the analytesdetermined In this method, samplesshall be extracted within sevendays of collection and extracts shallbe analyzed within 40 days ofextraction.

9.5 As a precaution against analyteand solvent loss or degradation,sample extracts are stored in glassbottles with Teflon lined caps, inthe dark, at -20 to -10 degrees C.

10 Sample extraction andconcentration

10.1 Retort10.1.1 Tare the retort sample cup and

cap to the nearest 0.1 gm. Transfer awell homogenized andrepresentative portion of the drillingfluid to be tested into the samplecup. Do not fill the retort cup to thetop so that excess sample must bewiped off. Place the cap on the cupand reweigh. Record the weight ofthe sample to the nearest 0.1 g.

Note: on agitation, most drilling fluidsentrain air as small bubbles. The extentof air entrainment is uncertain and isdifficult to detect when the mud ispoured into the retort cup. By weighingthe drilling fluid, the quantitativedetection of diesel oil is improved. Inaddition, by using a gravimetricmeasurement of the amount of sample,the retort cup does not need to becompletely filled. This procedure avoidsthe error that occurs when the cup isfilled and the oil rises to the surface of

the sample and must be wiped off (asoccurs if the manufacturer's instructionsare followed), thus resulting in a loss ofoil.10.1.2 Follow the manufacturer's

instructions for retort of the drillingfluid. Substitute 6 g of looselypacked glass wool for the steel woolinthe manufacturer's instructionsand distill the sample into a glassreceiver. The presence of solids inthe distillate require that thedistillation be rerun starting with anew portion of sample. Placing moreglass wool in the retort expansionchamber, per the manufacturer'sinstructions, will help prevent thesolids from being carried over in thedistillation.

10.1.3 QC standard-used for tests ofinitial (section 8.2) and on-going(section 12.5) precision andaccuracy. For the initial set of foursamples (section 8.2) and for eachset of samples started through theretort process on the same workingday (to a maximum of five), preparea QC sample as follows:

10.1.3.1 Place the reference drillingfluid containing 10,000-50,000 mg/kg of diesel oil (section 6.6) in theretort cup beginning in section 10.1.

10,1.3.2 Alternatively, pipet 1.00 mL ofthe solution containing 600 mg/mLof diesel oil in methylene chlorideinto a clean retort cup and weigh tothe nearest mg. Record the weightof the oil to the nearest mg. Addapproximately 10 mL of reagentwater to the cup and place the capon the cup.

10.1.3.3 Analyze the QC standardbeginning with section 10.1.2 thenproceeding to section 10.2

10.1.4 Blank-For the initial set of foursamples (section 8.2) and for eachset-for samples started through theretort process on the same workingday (to a maximum of five), preparea blank as follows:

10.1.4.1 Place 10 mL of reagent water ina clean, tared, retort cup and weighto the nearest mg. Record theweight of the reagent water.

10.1.4.2 Analkyze the blank beginningwith section 10.1.2 then proceedingto section 10.2.

10.2 Extraction and drying10.2.1 After the distillation is complete,

pour the retort distillate into a 60mL separatory funnel.Quantitatively rinse the innersurfaces of the retort stem andcondenser with methylene chlorideinto the separatory funnel. Rinse thereceiver with two full receivervolumes of methylene chloride andadd to the separatory funnel.

10.2.2 Stopper and shake the funnel forone minute, with periodic venting toprevent a build up of gas pressure.Allow the layers to separate.

10.2.2 Prepare a glass filtering funnelby plugging the bottom with a pieceof glass wool and pouring in 1-2inches of anhydrous sodium sulfate.Wet the funnel with a small portionof methylene chloride and allow themethylene chloride to drain to awaste container. Alternatively, adrying column may be used.

10.2.3 Place the glass filtering funnel ordrying column into the top of aKuderna-Danish (K-D) flaskequipped with a preweighed 10 mLreceiving flask. Add a preweighedboiling chip to the receiving flask.Drain the methylene chloride(lower) layer into the glass filteringfunnel or drying column, and collectthe extract in the K-D flask.

10.2.4 Repeat the methylene chlorideextraction twice more, rinsing theretort with two thorough washingseach time and draining eachmethylene chloride extract throughthe funnel or drying column into theK-D flask.

10.3 Concentration10.3.1 Place a Snyder column on the K-

D flask. Prewet the Snyder columnby adding about one mL methylenechloride to the top. Place the K-Dapparatus on a hot water bath (60-65 degrees C) so that theconcentrator tube is partiallyimmersed in the hot water, and theentire lower rounded surface of theflask is bathed with hot vapor.Adjust the vertical position and thewater temperature as required tocomplete the concentration in 15-20 minutes. At the proper rate ofdistillation, the balls of the columnwill actively chatter but thechambers will not flood withcondensed solvent. Concentrate thesample until it is free of methylenechloride. Remove the K-Dapparatus from the hot water bathand allow to cool.

10.3.2 Weigh and record the finalweight of the receiving flask.

10.3.3 Dissolve the oil in methylenechloride and adjust the final volumeto 1.0 mL. If the extract did notconcentrate to a final volume of 1.0mL or less, adjust the final volumeto 10.0 mL.

11 Gas chromatography11.1 Table 3 lists the retention times

that can be achieved under theconditions in table 2 for the n-alkanes of interest. Examples ofseparations that can be achieved

Federal Reclister / Vol. 53, No. 204 / Friday, October 21, 1988 / Proposed Rules41387


Federal Register / Vol. 53, No. 204 / Friday, October 21, 1988 1 Proposed Rules

are shown in figure 1.1 Other retortdevices, columns, chromatographicconditions, or detectors may beused if the EDL stated in thismethod and the requirements ofsection 8.2 are met.

11.2 Using a micropipet ormicrosyringe, transfer equal 100 jiLvolumes of the sample extract orQC standard extract (section 10.3.3)and the TCB internal standardsolution (section 6.4) into a GCinjection vial. Cap tightly and mixthoroughly.

11.3 Inject I pL of the sample extractor reference standard into the GCusing the conditions in table 2.

11.4 Begin data collection and thetemperature program at the time ofinjection.

11.5 If the area of any peak exceedsthe calibration range of the system,make a 10-fold dilution of theextract (section 10.3.3), mix a 100 ILaliquot of this dilute extract with100 g.L of the internal standardsolution (section 6.4), andreanalyze,

12 System and laboratory performance12.1 At the beginning of each working

day during which analyses areperformed, GC calibration isverified. For these tests, analysis ofthe 300 mg/mL calibration standard(table 1) shall be used to verify allperformance criteria. Adjustmentand/or recalibration (per section 7)shall be performed until allperformance criteria are met. Onlyafter all performance criteria aremet may the QC standard andsamples be analyzed.

12.2 Retention times12.2.1 Retention time of the internal

standard--:-the absolute retentiontime of the TCB internal standardshall be within the range of 7.96-8.08 minutes.

12.2.2 Relative retention times of the n-alkanes-the retention times of then-alkanes relative to the TCB

I Figure i--Sample Chronatograms. is notpublished in the Federal Register but is available inthe public docket. See "Addresses" section. -

internal standard shall be withinthe limits given in table 4.

12.3 Calibration verification12.3.1 Compute the response factor for

each n-alkane by the internalstandard technique (section 7.2).

12.3.2 For each n-alkane, compare theresponse factor with the responsefactor from the initial calibration(section 7.2.2). If all response factorsare within +/ - 15 percent of theirrespective values in the calibrationdata, system calibration has beenverified. If not, prepare a freshcalibration standard and repeat thetest (section 12.1), or recalibrate(section 7).

12.4 Multiple GC peaks-each n-alkane shall give a single, distinctGC peak.

12.5 On-going precision and accuracy12.5.1 Compute the oil content

concentration and the concentrationof diesel oil in the QC standard ineach sample set (section 10.1.3)prior to analysis of any sample inthe set.

12.5.2 Compare the concentration withthe QC limit in table 4. If theconcentrations of oil content and ofdiesel oil in the QC standard meetthe acceptance criteria, systemperformance is acceptable andanalysis of samples may proceed. If,however, the concentrations do notmeet the acceptance criteria, systemperformance is unacceptable. In thisevent, correct the problem,reprocess the sample set (section10), and repeat the on-goingprecision adn accuracy test(sections 10.1.3 and 12.5).

12.5.3 Add results that pass thespecifications in section 12.5.2 toinitial and previous on-going data.Update QC charts to form a graphicrepresentation of continuedlaboratory performance. Developstatements of laboratory accuracyfor oil content and diesel oil indrilling fluids by accuracy for oilcontent and diesel oil in drillingfluids by calculating the averagepercent'recovery (R) and thestandard deviation of percent

recovery (sr). Express the accuracystatement as a recovery intervalfrom R-2 sr to R+2 sr. Forexample, if R=95 percent and sr=5percent, the accuracy is 85-105percent.

13 Qualitative determination13.1 Compare the sample

chromatogram to the chromatogramof the standard. If the samplecontains diesel oil, the major peakspresent in the standard (n-alkanes)will also be present in the sampleand have the same relative intensityand pattern (see figure 1).

13.2 Relative retention times-themajor n-alkane peaks (table 3) shallbe present and shall be within thelimits in table 3.

13.3 Some mineral oil lubricityadditives have similarchromatographic patterns to that ofdiesel oil. The presence of early,smaller peaks with retention timesin the range of one to four minuteswill differentiate between distillatescontaining only mineral oil andthose with diesel oil.

14 Quantitative determination14.1 Oil content by gravimetry14.1.1 Subtract the weight of the

preweighed receiving flask andboiling chip (10.2.3) from the finalweight of the receiving flask (10.3.2).

14.1.2 Calculate the concentration ofoil in the sample using the followingequation:

Equation 7:

WfC (mg/kg)= - x 100

Ws

where:Wf=final weight of oil in mg (from 14.1.1)Ws=wet weight of sample in grams (from

10.1.1)

14.2 Diesel oil by gas chromatography14.2.1 Compute the concentration of

diesel oil in the sample extractusing the combined response factorgiven in section 7.3.3 and either ofthe following equations:

E Cex (mg/mL)=(Cis) [RF(1)+RF(2) . . . + RF(n)I

(RF combined)Equation 5.

41388



Cex (mg/mL)=(Cis} [As(1)+As (2). . . + Asfn}]'

(Ais) (RF combined)

where:Cex Is the concentration of the oil in the

extract

14.2.2 Calculate the concentration ofdiesel oil (in mg/kg) in the sampleas follows:

Equation 6:

C (mg/kg)= (Cex) (Vex) A 10(Ws)

where:Vex=final extract volume in mL (from 10.3.3

or 14.2.3)Ws=wet weight of samle in grams (from

10.1.1)14.2.3 If area of any peak in the

chromatographic pattern exceedsthe calibration range of the GC, theextract is diluted by a factor of 10with methylene chloride, 100 IL iswithdrawn and mixed with 100,uLof the internal standard solution(section 6.4) and the diluted extractis reanalyzed.

14.3 Results of analyses of drillingfluids are reported in units of mg/kg(wet weight) to three significantfigures. Results for samples thathave been diluted are reported atthe least dilute level at which thepeak areas are within thecalibration range (section 14.2.3).

15 Complex samples15.1 The most common interference in

the determination of diesel oil isfrom mineral oil in the drilling fluid(see sections 3 and 13). Drillingfluids may also contain proprietarylubricity additives that can interferewith the identification andquantification of diesel oil.

15.2 The presence of mineral oil orother interfering oils and additivescan often be determined bycomparing the pattern ofchromatographic peaks in thesample with the patterns ofchromatographic peaks in thereference standard (sections 6.5 and10.1.3) and in the spiked sample(section 8.3).

15.3 In cases where there is a mixtureof diesel and mineral oil, theanalyst may have to choose some ofthe smaller early or late elutingpeaks present in thechromatographic pattern of thediesel oil, and not present in thechromatographic pattern of the

mineral oil, to determine the dieselcontent. Quantification using thesepeaks is performed by using thesepeaks for calibration (section 7) andfor determination of the finalconcentration (section 14).

15.4 In extreme cases, the method ofstandard additions may be requiredto reliably quantitate the dieselcontent of a sample containinginterferences.

16 Method performance16.1 This method was developed by

two laboratoreis that tested fordiesel oil in drilling fluids (mainlydrilling muds) over a two-yearperiod. The performance data forthis method is based on theperformance of the method in thesetwo laboratories (reference 8).

16.2 The most commonly occurringdrilling fluid in the tests of thismethod was a seawaterlignosulfonate mud (EPA GenericMud No. 8). The estimated detectionlimit for diesel oil in this mud is 100jig/kg.

References1. Brown, John S, "Organic Chemical

Characterization of Diesel and Mineral OilsUsed as Drilling Mud Additives", Proceedingsof Tenth Annual Analytical Symposium,USEPA. Industrial Technology Division (WH-552), 401 M St. Washington DC 20460, March19-20 1986.

2. Brown, John S, "Final Report forResearch Program on: Organic ChemicalCharacterization of Diesel and Mineral Oilsused as Drilling Mud Additives", Phase ILContract Reference Agreement No. 501-P-5476R, to Offshore Operators Committee,Environmental Subcommittee, Houston, TX,Prepared by Battelle Ocean Science andTechnology Department, 397 Washington St.Duxbury MA 02332.

3. "Carcinogens-Working WithCarcinogens", Department of Health,Education, and Welfare, Public HealthService, Center for Disease Control, NationalInstitute for Occupational Safety and Health,Publication No. 77-206, August 1977.

4. "OSHA Safety and Health Standards,General Industry", [29 CFR 1910].Occupational Safety and HealthAdministration, OSHA 2206 (Revised,January 1976).

5. "Safety in Academic ChemistryLaboratories", American Chemical SocietyPublication, Committee Chemical Safety, 3rdEdition, 1979.

6. "Handbook of Analytical Quality Controlin Water and Wastewater Laboratories",USEPA. EMSL. Cincinnati, OH 45268, EPA-600/4-79-019 (March 1979).

7. "Standard Practice for Sampling Water".ASTM Annual Book of Standards, ASTM,Philadelphia, PA 76 (1980).

8. Rushneck, D R, and Eynon B P,"Precision and Recovery Analysis of DPMPDiesel Measurements", Memorandum toDennis Ruddy, USEPA, Industrial TechnologyDivision (WH-552, 401 M St SW,Washington DC 20460 (23 August 1987, draft).

TABLE 1-CONCENTRATION OFCALIBRATION STANDARDS

Wt of DieselExpected oil in 10 mL Concentration In

concentration In voumetric standardsample(g)

50,000 mg/kg . Use undilutedoil.

30,000 mg/kg . 7.6 ......... 760 mg/mL10,000 mg/kg . 3.0 ...................... 300 mg/mL5,000 mg/kg ........ 1.5 ...................... 150 mg/mL2,000 mg/kg ........ 0.6 ..................... 60 mg/mL

'Weigh oil to the nearest mg.

TABLE 2- -GAS CHROMATOGRAPHICOPERATING CONDITIONS-METHOD 16511

Injection port, transfer line, and detector tempera-tures = 275 C

Column temperature program:Initial temperature: 90 CInitial time: 0 minutesRamp: 90 -250 C @ 5 C per minFinal temperature: 250 CFinal hold: 10 minutes or until all peaks have

eluted.Carrier gas and flow rates:

Carrier: nitrogen or heliumVelocity: 20 - 40 cm/sec @ 90 C

Split ratio: 80:1 - 120:1Makeup gas: as required by manufacturer

Hydrogen and air flow rate: as specified by manu-facturer

Detector amplifier settings: 10-11 amp full scale.Attention Is adjusted so that the highest peaks are

on scale in the most concentrated standard.Recorder. Chart speed of 1 - 2 cm/mtn (fixed).

I Conditions are approximate and can be adjustedto meet the performance criteria In section 12.

TABLE 3.-RETENTION TIMES AND RELA-TIVE RETENTION TIME LIMITS FORMAJOR COMPONENTS OF DIESEL OIL-METHOD 1651

Retention timeCompound

Mean Relative

TCB .......................................... 8.0 1.00-1.00n-C 12 ........................................ 9.9 1.22-1.24n-C14 ....................................... 12.6 1.55-1.57n-C16 ....................................... 15.3 1.98-1.92n-C18 ....................................... 17.9 2.21-2.25n-C20 ....................................... 20.4 2.52-2.56n-C22 ................... 22.9 2.82-2.88n-C24 .................. 25.2 3.12-3.15

Equation 6:

41389



TABLE 4-OC ACCEPTANCE CRITERIA FOR PRECISION AND RECOVERY-METHOD 1651 1

Analyte Test concentration (mg/ Limit for s (mg/kg) Range for X (mg/kg) Range for P (mg/kg)kg)

Oil Content by grav ........................................... 20,000 3,400 18,000-23,700 16,700-24,9001 n 0.17n 0.88n-1.16n 0.82n-1.22n

Diesel oil by GC ....................................................................... 20000 3,600 17,200-20,300 13,600-21,4002 n 0.18n 0.80n-1.08n 0.73n-1.14n

'Preliminary specifications; final specifications to be developed at a later date.2 For other test concentrations in the range of 1,000-50,000 mg/kg, assuming a spike to background ratio of 5:1.

Table 5-0C ACCEPTANCE CRITERIAFOR DUPLICATES-METHOD 1651

Concentration Relativedetected (mg/ percent oil Difference

kg) content diesel oil

500 36 94750 30 68

1,000 38 542,000 24 345,000 21 22

10,000 21 1820,000 20 1650,000 20 15

Dated: October 3, 1988.William A. Whittingon,Acting Assistant Administrator for Water.[FR Doc. 88-23893 Filed 10-20-88; 8:45 am]BILLING CODE 6560-50-M

DEPARTMENT OF DEFENSE

48 CFR Parts 214 and 215

Department of Defense FederalAcquisition Regulation Supplement;Sealed Bidding

AGENCY: Department of Defense [DoD).ACTION: Proposed rule and request forpublic comments.

SUMMARY: The Defense AcquisitionRegulatory (DAR) Council is consideringchanges to the Defense FederalAcquisition Regulation Supplement(DFARS), Subpart 214.2 and 215.4 todelete this coverage as a result of recentrecommendations to add similarcoverage to the Federal AcquisitionRegulation. The proposed additions tothe Federal Acquisition Regulation are

also publshed in this issue of the FederalRegister.DATE: Comments on this proposedrevisions should be submitted in writingto the Executive Secretary, DARCouncil, at the address shown below, onor before December 20, 1988, to beconsidered in the formulation of thefinal rule. Please cite DAR Case 88-50 inall correspondence relating to this issue.ADDRESS: Interested parties shouldsubmit written comments to: DefenseAcquisition Regulatory Council, ATTN:Mr. Charles W. Lloyd, ExecutiveSecretary, DAR Council, ODASD (P)/DARS, c/o OASD(P&L) (MRS), Room3D139, The Pentagon, Washington, DC20301-3062.FOR FURTHER INFORMATION CONTACT:Mr. Charles W. Lloyd, ExecutiveSecretary, DAR Council, (202) 697-7266.SUPPLEMENTARY INFORMATION:

A. BackgroundThe Defense Acquisition Regulatory

Council has reviewed the DoD FARSupplement and determined that thecoverage at 214.270 and 215.470 isappropriate for inclusion in the FederalAcquisition Regulation.

B. Regulatory Flexibility ActThe proposed rule does not constitute

a significant FAR revision within themeaning of FAR 1.501 and Pub. L. 98-577and publication for public comment isnot required. Master solicitations, in andof themselves are nothing more than apackage of solicitations and clauses sentto contractors who are on biddersmailing lists and the package is referredto when an actual solicitation is issued.

Therefore, the Regulatory Flexibility Actdoes not apply. However, commentsfrom small entities concerning theaffected DFARS Subpart will also beconsidered in accordance with section610 of the Act. Such comments must besubmitted separately and cite DFARSCase 88-610D in correspondence.

C. Paperwork Redcution Act

The ruel does not contain informationcollection requirements which requirethe approval of 0MB under 44 U.S.C.3501.

List of Subjects in 48 CFR Parts 214 and215

Government procurement.

October 13, 1988.Charles W. Lloyd,Executive Secretary, Defense AcquisitionRegulatory Council.

Therefore, it is proposed to amend 48CFR Parts 214 and 215 as follows:

The authority citation for 48 CFR Parts214 and 215 continues to read as follows:

Authority: 5 U.S.C. 301, 10 U.S.C. 2202, DoDDirective 5000.35, and DoD FAR Supplement201.301.

PART 214-EALED BIDDING

214.270 [Removed]2. Section 214.270 is removed.

PART 215-CONTRACTING BYNEGOTIATION

215.470 [Removed]3. Section 215.470 is removed.

[FR Doc. 88-24411 Filed 10-20-88; 8:45 am]BILLING CODE 3810-01-M

41390 ,


Documents

Federal Register Vol. 53, No. 204 Friday, October 21, 1988