Effluent Limitations Guidelines and New Source Performance Standards for the Oil and Gas Extraction Point Source Category; OMB Approval Under the Paperwork Reduction Act: Technical Amendment

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 9 and 435

[FRL-6929-8]

RIN 2040-AD14

Effluent Limitations Guidelines and New Source Performance Standards for the Oil and Gas Extraction Point Source Category; OMB Approval Under the Paperwork Reduction Act: Technical Amendment

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Final Rule; technical amendment.

SUMMARY:

EPA is publishing final regulations establishing technology-based effluent limitations guidelines and standards for the discharge of synthetic-based drilling fluids (SBFs) and other non-aqueous drilling fluids from oil and gas drilling operations into waters of the United States. Oil and gas extraction facilities generate cuttings wastes from drilling operations. This regulation applies to existing and new sources that perform oil and natural gas extraction drilling in certain offshore and coastal waters. The final rule allows a controlled discharge of SBF-cuttings anywhere offshore of Alaska and offshore of the rest of the United States beyond three miles from shore. This regulation prohibits discharge of such fluids in coastal Cook Inlet, Alaska, unless certain findings are made by the permit authority. The final rule prohibits the discharge of SBFs not associated with drill cuttings into all waters of the United States.

Compliance with this rule is estimated to reduce the annual discharge of cuttings by 118 million pounds per year for new and existing sources. This rule will also lead to a decrease of 2,927 tons of air emissions and 200,817 barrels of oil equivalent (BOE) per year for new and existing sources. EPA estimates that the rule will result in annual savings of $48.9 million and no adverse economic impacts to the industry as a whole. EPA also incorporated Best Management Practices (BMPs) into the final rule to provide industry with additional flexibility in meeting today's final rule. In compliance with the Paperwork Reduction Act (PRA), this action also makes a technical amendment to the table in part 9 that lists the Office of Management and Budget (OMB) control numbers issued under the PRA for today's final rule. EPA is amending part 9 to include the OMB control number for the information collection requirements associated with the BMPs promulgated in today's final rule.

DATES:

This regulation shall become effective February 21, 2001. For judicial review purposes, this final rule is promulgated as of 1 p.m. Eastern Time on February 5, 2001, as provided in 40 CFR 23.2. The incorporation by reference of certain publications listed in the regulations is approved by the Director of the Office of Federal Register as of February 21, 2001.

ADDRESSES:

The public record is available for review in the EPA Water Docket, East Tower Basement, Room EB-57, 401 M St. SW., Washington, DC 20460. The public record for this rule has been established under docket number W-98-26, and includes supporting documentation, but does not include any information claimed as Confidential Business Information (CBI). The record is available for inspection from 9 a.m. to 4 p.m., Monday through Friday, excluding legal holidays. For access to docket materials, please call (202) 260-3027 to schedule an appointment.

FOR FURTHER INFORMATION CONTACT:

For additional technical information contact Mr. Carey A. Johnston at (202) 260-7186 or send E-mail to: johnston.carey@epa.gov. For additional economic information contact Mr. James Covington at (202) 260-5132 or send E-mail to: covington.james@epa.gov.

SUPPLEMENTARY INFORMATION:

Regulated Entities

Entities potentially regulated by this action include:

Category

Examples of regulated entities

Industry

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

This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be regulated by this action. This table lists the types of entities that EPA is now aware could potentially be regulated by this action. Other types of entities not listed in the table could also be regulated. To determine whether your facility is regulated by this action, you should carefully examine the applicability criteria in 40 CFR part 435 (

see

§§ 435.10 and 435.40). If you have questions regarding the applicability of this action to a particular entity, consult the person listed for technical information in the preceding

FOR FURTHER INFORMATION CONTACT

section.

Compliance Dates

Deadlines for compliance with Best Practicable Control Technology Currently Available (BPT), Best Conventional Pollutant Control Technology (BCT), and Best Available Technology Economically Achievable (BAT) are established in National Pollutant Discharge Elimination System (NPDES) permits. A new source must comply with New Source Performance Standards (NSPS) on the date the new source commences discharging.

Technical Amendments to Part 9

EPA is amending the table of currently approved information collection request (ICR) control numbers issued by OMB for various regulations. The amendment updates the table to list those information collection requirements promulgated under today's final rule. The affected regulations are codified at 40 CFR part 9. EPA will continue to present OMB control numbers in a consolidated table format to be codified in 40 CFR part 9 of the Agency's regulations, and in each CFR volume containing EPA regulations. The table lists CFR citations with reporting, recordkeeping, or other information collection requirements, and the current OMB control numbers. This listing of the OMB control numbers and their subsequent codification in the CFR satisfies the requirements of the Paperwork Reduction Act (44 U.S.C. 3501

et seq.

) and OMB's implementing regulations at 5 CFR part 1320.

This ICR was previously subject to public notice and comment prior to OMB approval. Due to the technical

nature of the table, EPA finds that further notice and comment is unnecessary. As a result, EPA finds that there is “good cause” under section 553(b)(B) of the Administrative Procedure Act, 5 U.S.C. 553(b)(B), to amend this table without prior notice and comment. As a result of today's technical amendment pertaining to BMPs, EPA is now authorized under the Paperwork Reduction Act to conduct or sponsor the information collection requirements in 40 CFR 435.13, 435.15, 435.43, and 435.45.

Supporting Documentation

The rules promulgated today are supported by several major documents:

1. “Economic Analysis of Final Effluent Limitations Guidelines and Standards for Synthetic-Based Drilling Fluids and other Non-Aqueous Drilling Fluids in the Oil and Gas Extraction Point Source Category” (EPA-821-B-00-012). Hereafter referred to as the SBF Economic Analysis, this document presents the analysis of compliance costs and/or savings; facility closures; and changes in rate of return. In addition, impacts on employment and affected communities, foreign trade, specific demographic groups, and new sources also are considered.

2. “Development Document for Final Effluent Limitations Guidelines and Standards for Synthetic-Based Drilling Fluids and other Non-Aqueous Drilling Fluids in the Oil and Gas Extraction Point Source Category” (EPA-821-B-00-013). Hereafter referred to as the SBF Development Document, the document presents EPA's technical conclusions concerning the promulgated rules. This document describes, among other things, the data collection activities, the wastewater treatment technology options, effluent characterization, effluent reduction of the wastewater treatment technology options, estimate of costs to the industry, and estimate of effects on non-water quality environmental impacts.

3. “Environmental Assessment of Final Effluent Limitations Guidelines and Standards for Synthetic-Based Drilling Fluids and other Non-Aqueous Drilling Fluids in the Oil and Gas Extraction Point Source Category” (EPA-821-B-00-014). Hereafter referred to as the SBF Environmental Assessment, the document presents the analysis of water quality impacts for each regulatory option. EPA describes the environmental characteristics of SBF drilling wastes, types of anticipated impacts, and pollutant modeling results for water column concentrations, pore water concentrations, and human health effects via consumption of affected seafood.

4. “Statistical Analyses Supporting Final Effluent Limitations Guidelines and Standards for Synthetic-Based Drilling Fluids and other Non-Aqueous Drilling Fluids in the Oil and Gas Extraction Point Source Category” (EPA-821-B-00-015). Hereafter referred to as the SBF Statistical Support Document, this document presents analyses of retention on cuttings of SBF. EPA describes the performance characteristics of cuttings treatment technologies and calculates summary statistics for use as numerical limits.

How To Obtain Supporting Documents

All documents are available from the National Service Center for Environmental Publications, PO Box 42419, Cincinnati, OH 45242-2419, (800) 490-9198. The supporting technical documentation (

e.g.

, SBF Development Document) and previous technical documentation and Federal Register notices can also be obtained on the Internet, located at WWW.EPA.GOV/OST/GUIDE. This website also links to an electronic version of today's final rule.

Overview

This preamble includes a description of the legal authority for these final regulations; a summary of the final regulations; background information on the industry and its processes; a description of the technical and economic methodologies and data used by EPA to develop these regulations; and a summary of EPA responses to major comments received on the Proposal (February 3, 1999; 64 FR 5488) and Notice of Data Availability (April 21, 2000; 65 FR 21548). The definitions, acronyms, and abbreviations used in this preamble are defined in Appendix A.

Organization of This Document

I. Legal Authority

II. Background

A. Clean Water Act

B. Pollution Prevention Act

C. Profile of Industry

D. Proposed Rule

E. Notice of Data Availability

III. Summary of Data and Information Received in Response to the Notice of Data Availability

A. Pollutant Loading and Numeric Limit Analyses

B. Compliance Costs Analyses

C. Economic Impacts Analyses

D. Water Quality Impact and Human Health Analyses

E. Non-Water Quality Environmental Impact Analyses

F. Compliance Analytical Methods

IV. Summary of Revisions Based on Notice of Data Availability Comments

A. Pollutant Loading Analyses

B. Compliance Costs Analyses

C. Economic Impacts Analyses

D. Water Quality Impact and Human Health Analyses

E. Non-Water Quality Environmental Impact Analyses

F. Numerical Limits for Retention of SBF Base Fluid on SBF-cuttings

V. Development and Selection of Effluent Limitations Guidelines and Standards

A. Waste Generation and Characterization

B. Selection of Pollutant Parameters

C. Regulatory Options Considered and Selected for Drilling Fluid Not Associated with Drill Cuttings

D. BPT Technology Options Considered and Selected for Drilling Fluid Associated with Drill Cuttings

E. BCT Technology Options Considered and Selected for Drilling Fluid Associated with Drill Cuttings

F. BAT Technology Options Considered and Selected for Drilling Fluid Associated with Drill Cuttings

G. NSPS Technology Options Considered and Selected for Drilling Fluid Associated with Drill Cuttings

H. PSES and PSNS Technology Options

I. Best Management Practices (BMPs) to Demonstrate Compliance with Numeric BAT Limitations and NSPS for Drilling Fluid Associated with Drill Cuttings

VI. Costs and Pollutant Reductions for Final Regulation

A. Compliance Costs

B. Pollutant Reductions

VII. Economic Impacts of Final Regulation

A. Impacts Analysis

B. Small Business Analysis

VIII. Water Quality and Non-Water Quality Environmental Impacts of Final Regulation

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

B. Water Quality Modeling

C. Human Health Effects Modeling

D. Seabed Surveys

E. Energy Impacts

F. Air Emission Impacts

G. Air Emissions Monetized Human Health Benefits

H. Solid Waste Impacts

I. Other Factors

IX. Regulatory Requirements

A. Executive Order 12866: Regulatory Planning and Review

B. Regulatory Flexibility Act (RFA), as amended by the Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 U.S.C. 601

et seq.

C. Submission to Congress and the General Accounting Office

D. Paperwork Reduction Act

E. Unfunded Mandates Reform Act

F. Executive Order 13084: Consultation and Coordination with Indian Tribal Governments

G. Executive Order 13132: Federalism

H. National Technology Transfer and Advancement Act

I. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks

J. Executive Order 13158: Marine Protected Areas

X. Regulatory Implementation

A. Implementation of Limitations and Standards

B. Upset and Bypass Provisions

C. Variances and Modifications

D. Relationship of Effluent Limitations to NPDES Permits & Monitoring Requirements

E. Analytical Methods

Appendix A: Definitions, Acronyms, and Abbreviations Used in This Preamble

I. Legal Authority

EPA is promulgating these regulations under the authority of sections 301, 304, 306, 307, 308, 402, and 501 of the Clean Water Act, 33 U.S.C. 1311, 1314, 1316, 1317, 1318, 1342 and 1361. The technical amendment to part 9 is promulgated under the authority of 7 U.S.C. 135

et seq.

, 136-136y; 15 U.S.C. 2001, 2003, 2005, 2006, 2601-2671; 21 U.S.C. 331j, 346a, 348; 31 U.S.C. 9701; 33 U.S.C. 1251

et seq.

, 1311, 1313d, 1314, 1318, 1321, 1326, 1330, 1342, 1344, 1345 (d) and (e), 1361; E.O. 11735, 38 FR 21243, 3 CFR, 1971-1975 Comp. p. 973; 42 U.S.C. 241, 242b, 243, 246, 300f, 300g, 300g-1, 300g-2, 300g-3, 300g-4, 300g-5, 300g-6, 300j-1, 300j-2, 300j-3, 300j-4, 300j-9, 1857

et seq.

, 6901-6992k, 7401-7671q, 7542, 9601-9657, 11023, 11048.

II. Background

A. Clean Water Act

Congress adopted the Clean Water Act (CWA) to “restore and maintain the chemical, physical, and biological integrity of the Nation's waters” (Section 101(a), 33 U.S.C. 1251(a)). To achieve this goal, the CWA prohibits the discharge of pollutants into navigable waters except in compliance with the statute. The Clean Water Act confronts the problem of water pollution on a number of different fronts. Its primary reliance, however, is on establishing restrictions on the types and amounts of pollutants discharged from various industrial, commercial, and public sources of wastewater.

Direct dischargers must comply with effluent limitations in National Pollutant Discharge Elimination System (“NPDES”) permits; indirect dischargers must comply with pretreatment standards. These limitations and standards are established by regulation for categories of industrial dischargers and are based on the degree of control that can be achieved using various levels of pollution control technology.

1. Best Practicable Control Technology Currently Available (BPT)—Section 304(b)(1) of the CWA

Section 304(b)(1)(A) of the CWA requires EPA to identify effluent reductions attainable through the application of, “best practicable control technology currently available for classes and categories of point sources.” Generally, EPA determines BPT effluent levels based upon the average of the best existing performances by plants of various sizes, ages, and unit processes within each industrial category or subcategory. In industrial categories where present practices are uniformly inadequate, however, EPA may determine that BPT requires higher levels of control than any currently in place if the technology to achieve those levels can be practicably applied (

see

A Legislative History of the Federal Water Pollution Control Act Amendments of 1972, U.S. Senate Committee of Public Works, Serial No. 93-1, January 1973, p. 1468).

In addition, CWA Section 304(b)(1)(B) requires a cost assessment for BPT limitations. In determining the BPT limits, EPA must consider the total cost of treatment technologies in relation to the effluent reduction benefits achieved. This inquiry does not limit EPA's broad discretion to adopt BPT limitations that are achievable with available technology unless the required additional reductions are “wholly out of proportion to the costs of achieving such marginal level of reduction.” (

see

Legislative History, op. cit. p. 170). Moreover, the inquiry does not require the Agency to quantify benefits in monetary terms (

e.g.

, American Iron and Steel Institute v. EPA, 526 F. 2d 1027 (3rd Cir., 1975)).

In balancing costs against the benefits of effluent reduction, EPA considers the volume and nature of expected discharges after application of BPT, the general environmental effects of pollutants, and the cost and economic impacts of the required level of pollution control. In developing guidelines, the Act does not require consideration of water quality problems attributable to particular point sources, or water quality improvements in particular bodies of water.

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

The CWA establishes BAT as a principal means of controlling the discharge of toxic and non-conventional pollutants. In general, BAT effluent limitations guidelines represent the best existing economically achievable performance of direct discharging plants in the industrial subcategory or category. The factors considered in assessing BAT include the cost of achieving BAT effluent reductions, the age of equipment and facilities involved, the processes employed, engineering aspects of the control technology, potential process changes, non-water quality environmental impacts (including energy requirements), and such factors as the Administrator deems appropriate. The Agency retains considerable discretion in assigning the weight to be accorded to these factors. An additional statutory factor considered in setting BAT is economic achievability. Generally, the achievability is determined on the basis of the total cost to the industrial subcategory and the overall effect of the rule on the industry's financial health. BAT limitations may be based upon effluent reductions attainable through changes in a facility's processes and operations. As with BPT, where existing performance is uniformly inadequate, BAT may be based upon technology transferred from a different subcategory within an industry or from another industrial category. BAT may be based upon process changes or internal controls, even when these technologies are not common industry practice.

3. Best Conventional Pollutant Control Technology (BCT)—Section 304(b)(4) of the CWA

The 1977 amendments to the CWA required EPA to identify effluent reduction levels for conventional pollutants associated with BCT technology for discharges from existing industrial point sources. BCT is not an additional limitation, but replaces Best Available Technology (BAT) for control of conventional pollutants. In addition to other factors specified in section 304(b)(4)(B), the CWA requires that EPA establish BCT limitations after consideration of a two part “cost-reasonableness” test. EPA explained its methodology for the development of BCT limitations in July 1986 (51 FR 24974).

Section 304(a)(4) designates the following as conventional pollutants: biochemical oxygen demand (BOD

5

), total suspended solids (TSS), fecal coliform, pH, and any additional pollutants defined by the Administrator as conventional. The Administrator designated oil and grease as an additional conventional pollutant on July 30, 1979 (44 FR 44501).

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

NSPS reflect effluent reductions that are achievable based on the best available demonstrated control technology. New facilities have the opportunity to install the best and most efficient production processes and wastewater treatment technologies. As a result, NSPS should represent the greatest degree of effluent reduction attainable through the application of the best available demonstrated control technology for all pollutants (

i.e.,

conventional, non-conventional, and priority pollutants). In establishing NSPS, EPA is directed to take into consideration the cost of achieving the effluent reduction and any non-water quality environmental impacts and energy requirements.

5. Pretreatment Standards for Existing Sources (PSES)—Section 307(b) of the CWA

PSES are designed to prevent the discharge of pollutants that pass through, interfere with, or are otherwise incompatible with the operation of publicly owned treatment works (POTWs). The CWA authorizes EPA to establish pretreatment standards for pollutants that pass through POTWs or interfere with treatment processes or sludge disposal methods at POTWs. Pretreatment standards are technology-based and analogous to BAT effluent limitations guidelines.

The General Pretreatment Regulations, which set forth the framework for implementing categorical pretreatment standards, are found at 40 CFR part 403. Those regulations contain a definition of pass through that addresses localized rather than national instances of pass through and establish pretreatment standards that apply to all non-domestic dischargers. See 52 FR 1586, January 14, 1987.

6. Pretreatment Standards for New Sources (PSNS)—Section 307(b) of the CWA

Like PSES, PSNS are designed to prevent the discharges of pollutants that pass through, interfere with, or are otherwise incompatible with the operation of POTWs. PSNS are to be issued at the same time as NSPS. New indirect dischargers have the opportunity to incorporate into their plants the best available demonstrated technologies. The Agency considers the same factors in promulgating PSNS as it considers in promulgating NSPS.

7. Best Management Practices (BMPs)

Sections 304(e), 308(a), 402(a), and 501(a) of the CWA authorize the Administrator to prescribe BMPs as part of effluent limitations guidelines and standards or as part of a permit. EPA's BMP regulations are found at 40 CFR 122.44(k). Section 304(e) of the CWA authorizes EPA to include BMPs in effluent limitations guidelines for certain toxic or hazardous pollutants for the purpose of controlling “plant site runoff, spillage or leaks, sludge or waste disposal, and drainage from raw material storage.” Section 402(a)(1) and NPDES regulations (40 CFR 122.44(k)) also provide for best management practices to control or abate the discharge of pollutants when numeric limitations and standards are infeasible. In addition, section 402(a)(2), read in concert with section 501(a), authorizes EPA to prescribe as wide a range of permit conditions as the Administrator deems appropriate in order to ensure compliance with applicable effluent limitations and standards and such other requirements as the Administrator deems appropriate.

8. CWA Section 304(m) Requirements

Section 304(m) of the CWA, added by the Water Quality Act of 1987, requires EPA to establish schedules for: (1) Reviewing and revising existing effluent limitations guidelines and standards; and (2) promulgating new effluent guidelines. On January 2, 1990, EPA published an Effluent Guidelines Plan (55 FR 80), in which schedules were established for developing new and revised effluent guidelines for several industry categories, including the oil and gas extraction industry. Natural Resources Defense Council, Inc., challenged the Effluent Guidelines Plan in a suit filed in the U.S. District Court for the District of Columbia, (

NRDC et al.

v.

Browner,

Civ. No. 89-2980). On January 31, 1992, the Court entered a consent decree (the “304(m) Decree”), which establishes schedules for, among other things, EPA's proposal and promulgation of effluent guidelines for a number of point source categories. The most recent Effluent Guidelines Plan was published in the

Federal Register

on August 31, 2000 (65 FR 53008). This plan requires, among other things, that EPA take final action regarding the Synthetic-Based Drilling Fluids Guidelines by December 2000.

B. Pollution Prevention Act

The Pollution Prevention Act of 1990 (PPA) (42 U.S.C. 13101

et seq.

, Public Law 101-508, November 5, 1990) “declares it to be the national policy of the United States that pollution should be prevented or reduced whenever feasible; pollution that cannot be prevented should be recycled in an environmentally safe manner, whenever feasible; pollution that cannot be prevented or recycled should be treated in an environmentally safe manner whenever feasible; and disposal or release into the environment should be employed only as a last resort * * *” (Sec. 6602; 42 U.S.C. 13101 (b)). In short, preventing pollution before it is created is preferable to trying to manage, treat or dispose of it after it is created. The PPA directs the Agency to, among other things, “review regulations of the Agency prior and subsequent to their proposal to determine their effect on source reduction” (Sec. 6604; 42 U.S.C. 13103(b)(2)). EPA reviewed this effluent guideline for its incorporation of pollution prevention.

According to the PPA, source reduction reduces the generation and release of hazardous substances, pollutants, wastes, contaminants, or residuals at the source, usually within a process. The term source reduction “include(s) equipment or technology modifications, process or procedure modifications, reformulation or redesign of products, substitution of raw materials, and improvements in housekeeping, maintenance, training or inventory control. The term “source reduction” does not include any practice which alters the physical, chemical, or biological characteristics or the volume of a hazardous substance, pollutant, or contaminant through a process or activity which itself is not integral to or necessary for the production of a product or the providing of a service.” 42 U.S.C. 13102(5). In effect, source reduction means reducing the amount of a pollutant that enters a waste stream or that is otherwise released into the environment prior to out-of-process recycling, treatment, or disposal.

In these final regulations, EPA supports pollution prevention technology by encouraging the appropriate use of synthetic-based drilling fluids (SBFs) based on the use of base fluid materials in place of traditional: (1) Water-based drilling fluids (WBFs); and (2) oil-based drilling fluids (OBFs) consisting of diesel oil/or and mineral oil. The appropriate use of SBFs in place of WBFs will generally lead to more efficient and faster drilling and a per well reduction in non-water quality environmental impacts (including energy requirements) and discharged pollutants. Use of SBFs may also lead to a reduced demand for new drilling rigs and platforms and development well drilling though the use directional and extended reach drilling. Discharges from SBF-drilling operations have lower aqueous and

sediment toxicities, lower bioaccumulation potentials, and faster biodegradation rates as compared to OBFs. In addition, polynuclear aromatic hydrocarbons (PAHs), including those which are priority pollutants, which are constituents in OBFs are not present in SBFs.

EPA considered a “zero discharge” requirement (

i.e.,

BAT/NSPS Option 3) for SBF-cuttings wastes and determined that under this requirement most operators would decrease the use of SBFs in favor of OBFs and WBFs due to lower OBF and WBF drilling fluid unit costs. EPA concluded that a zero discharge requirement for SBF-cuttings and the subsequent increased use of OBFs and WBFs would result in: (1) Unacceptable non-water quality environmental impacts (NWQIs); and (2) more pollutant loadings to the ocean due to operators switching from SBFs to less efficient WBFs.

The appropriate use of SBF in place of OBF will generally shorten the length of the drilling project and eliminate the need to barge to shore or re-inject OBF-waste cuttings, thereby reducing NWQI such as fuel use, air emissions, and land disposal of OBFs. The controlled discharge option also eliminates the risk of OBF and OBF-cuttings spills and cross-media contamination at land disposal operations. Operators would be increasing the toxicity of their drilling fluids and wastes by using OBFs in place of SBFs. As stated in April 2000 (65 FR 21557), EPA used SBF and OBF spill data in the final rule as a factor in supporting a controlled discharge option. U.S. Department of Interior, Minerals Management Service (MMS) spill data show that riser disconnects in deep water drilling can release approximately 2,400 barrels of neat SBF and these incidences occur in deep water on average two to three times per year due to riser failure (Docket No. W-98-26, Record No. IV.B.a.3). Riser disconnects in the deep water are a particular concern due to: (1) Increased riser tensioning; (2) deep water technical requirements (

e.g.,

riser verticality, increased use of top drive systems, multiple flex joints in riser, placement of well heads and upper casing sections in soft sea beds); and (3) deep water ocean environments (

e.g.,

uncharted eddy and loop currents) (Docket No. W-98-26, Record No. IV.B.a.4; Record No. IV.B.a.5). Use of WBFs in place of SBFs would also lead to: (1) An increase in NWQIs due to the increased length of the drilling project; and (2) a per well increase pollutants discharged due to poorer technical performance of WBFs. For these primary reasons, EPA rejected the zero discharge option.

In addition, the technology controls in the final regulation are based on a more efficient solids control technology to increase recycling of SBF in the drilling operation. Increased SBF recycling reduces the quantity of SBF required for drilling operations and the quantity of SBF discharged with drill cuttings. A discussion of this pollution prevention technology is contained in Section V.A of this preamble and in the SBF Development Document.

C. Profile of Industry

1. Well Drilling Process Description

The SBF Development Document presents a thorough description of the industry including drilling practices, solids control systems, and waste disposal operations. The following summary is excerpted from that technical document.

Drilling occurs in two phases: exploration and development. Exploration activities are those operations involving the drilling of wells to locate hydrocarbon bearing formations and to determine the size and production potential of hydrocarbon reserves. Development activities involve the drilling of production wells once a hydrocarbon reserve has been discovered and delineated.

Drilling for oil and gas is generally performed by rotary drilling methods which use a circularly rotating drill bit that grinds through the earth's crust as it descends. Drilling fluids are pumped down through the drill bit via a pipe that is connected to the bit, and serve to cool and lubricate the bit during drilling. The rock chips that are generated as the bit drills through the earth are termed “drill cuttings” or simply “cuttings.” The drilling fluid also serves to transport the drill cuttings back up to the surface through the space between the drill pipe and the well wall (this space is termed the annulus), in addition to controlling downhole pressure and stabilizing the well bore.

As drilling progresses, large pipes called “casing” are inserted into the well to line the well wall. Drilling continues until the hydrocarbon bearing formations are encountered. In areas where drilling fluids and drill cuttings are allowed to be discharged under the current regulations, well depths range from approximately 4,000 to 12,000 feet deep, and it takes approximately 20 to 60 days to complete drilling.

On the surface, the drilling fluid and drill cuttings undergo an extensive separation process to remove fluid from the cuttings. The fluid is then recycled into the system, and the cuttings become a waste product. The drill cuttings retain a certain amount of the drilling fluid that are discharged or disposed with the cuttings. Drill cuttings are discharged by the shale shakers and other solids separation equipment (

e.g.,

decanting centrifuges, mud cleaners, cuttings dryers). Drill cuttings are also cleaned out of the mud pits and from the solid separation equipment during displacement of the drilling fluid system (

i.e.,

accumulated solids). Intermittently during drilling, and at the end of the drilling process, drilling fluids may become wastes if they can no longer be reused or recycled.

In the relatively new area of ultra-deep water drilling (

i.e.,

water depths greater than 3,000 feet), new drilling methods are evolving which can significantly improve drilling efficiencies and thereby reduce NWQIs (

e.g.,

fuel, steel casing consumption, air emissions) and the per well amount of pollutants discharged. Subsea drilling fluid boosting, referred to as “dual gradient drilling,” is one such new drilling technology. Dual gradient drilling is similar to traditional rotary drilling methods as previously described with the exception that the drilling fluid is energized or boosted by use of a pump at or near the seafloor. By boosting the drilling fluid, the adverse effect on the wellbore caused by the drilling fluid pressure from the seafloor to the surface is eliminated, thereby allowing wells to be drilled with as much as a 50% reduction in the number of casing strings generally required to line the well wall. As a result of the reduced number of casing strings, dual gradient wells can be drilled almost one-third faster and with smaller hole sizes than conventional deep water drilling. Smaller hole sizes and faster drilling translate into fewer pollutants being discharged to the ocean and fewer NWQI. Dual gradient drilling technology can also potentially eliminate or reduce the amount of whole drilling fluid released to the environment during an inadvertent riser disconnect. Finally, dual gradient drilling technology can greatly reduce the potential release of drilling fluid when drilling through shallow sand intervals (

e.g.,

shallow water flow) (Docket No. W-98-26, Record No. IV.B.a.6).

Some dual gradient drilling systems require the separation of the largest cuttings (

e.g.,

larger than approximately

1/4

inch) at the seafloor since these cuttings may interfere with the rotatory action of subsea pumps (

e.g.,

electrical

submersible pumps). The larger cuttings are routed at the seafloor to a venturi action pump (with no moving parts), mixed with seawater, and pumped to a cuttings discharge hose at the seafloor within a 300 foot radius of the well site. The hose is perforated on the last 50 ft of its length to maximize the spread of cuttings. The action of pumping cuttings with seawater can be expected to have some cleaning and dispersion effect. A remotely operated vehicle (ROV) can also be used to reposition the subsea discharge hose to maximize cuttings dispersal. Representative samples of drill cuttings discharged at the seafloor can be transported to the surface by a ROV for purposes of monitoring. The drilling fluid, which is boosted at the seafloor and transports most of the drill cuttings (

e.g.,

95-98% of total cuttings generated) back to the surface, is processed as described in the general rotary drilling methods described above in this section.

A commercial potential determination is made at the completion of rotary drilling (

i.e.,

once the target oil or natural gas formations have been reached). The well is then made ready for production by a process termed “completion.” Completion involves cleaning the well to remove drilling fluids and debris, perforating the casing that lines the producing formation, inserting production tubing to transport the hydrocarbon fluids to the surface, and installing the surface wellhead. The well is then ready for production (

i.e.,

actual extraction of hydrocarbons).

2. Location and Activity

This rule establishes effluent limitations guidelines and standards that control discharges of SBF and SBF-cuttings throughout the Offshore subcategory beyond three miles from shore, except for Offshore Alaska where no three mile restriction applies. This rule prohibits discharge of SBF and SBF-cuttings in Upper (Coastal Subcategory) Cook Inlet, Alaska, unless operators meet criteria demonstrating that they are unable to: (1) Box and store their cuttings on-site for zero discharge cuttings transfer operations (

i.e.,

haul to shore for land disposal or re-injection at another rig or platform); or (2) re-inject their SBF-cuttings on-site. When Coastal Cook Inlet, AK, operators demonstrate to the NPDES controlling authority that they are unable to achieve zero discharge of their SBF-cuttings, they may discharge their SBF-cuttings under the same controls as exist for SBF-cuttings discharges in Offshore waters. Criteria for establishing when operators cannot achieve zero discharge are established in the final regulation. SBF-cuttings discharged in Offshore Cook Inlet, Alaska, are controlled in the same manner as other SBF-cuttings in other Offshore waters. This rule does not amend the requirements for zero discharge of drilling fluids and drill cuttings where they have already been prohibited from discharge.

Drilling is currently active in three regions: (1) The offshore waters beyond three miles from shore in the Gulf of Mexico (GOM); (2) offshore waters beyond three miles from shore in California; and (3) Cook Inlet, Alaska. Most drilling activity occurs in the GOM, where 1,302 wells were drilled in 1997, compared to 28 wells drilled in California and 7 wells drilled in Cook Inlet. In the GOM, over the last few years, there has been high growth in the number of wells drilled in deep water (

e.g.,

water depths greater than 1,000 feet). For example, in 1995, 84 wells were drilled in deep water, comprising 8.6% of all GOM wells drilled that year. By 1997, that number increased to 173 deep water wells drilled and comprised over 13% of all GOM wells drilled. Most recent 1999 data show that this trend is continuing as over 15% of all GOM wells drilled were in deep water. The increased activity in deep water increases the usefulness of SBFs. Operators drilling in deep water cite the following factors for selecting SBFs over WBFs and OBFs: (1) Potential for riser disconnect (

i.e.,

inadvertent releases of drilling fluid) in floating drill ships, which favors SBF over OBF; (2) higher daily drilling cost which more easily justifies use of more expensive SBFs over WBFs; and (3) greater distance to barge drilling wastes that may not be discharged (

i.e.,

OBFs, WBFs that fail the SPP Toxicity Test as currently required by EPA in Appendix 2 to Subpart A of 40 CFR part 435).

3. Drilling Wastestreams

Drilling fluids and drill cuttings are a major source of waste from exploratory and development well drilling operations. This final regulation establishes limitations for both the drilling fluid and the drill cuttings wastestream when SBFs are used. All other wastestreams and drilling fluids (

e.g.,

WBFs, OBFs) already have limitations; those limitations are outside the scope of this rule. The characteristics of both drilling fluids and drill cuttings wastestreams are summarized in Section V.A of this preamble. A more detailed discussion of the origins and characteristics of these wastes is also included in the SBF Development Document.

D. Proposed Rule

On February 3, 1999 (64 FR 5488), EPA published proposed effluent limitations guidelines for the discharge of SBF drilling fluids and drill cuttings into waters of the United States by existing and new facilities in the oil and gas extraction point source category.

EPA received comments on many aspects of the proposal. The majority of comments related to: (1) The proposed analytical test methods for stock and discharge limitations; (2) equipment used to set BAT and NSPS cuttings retention limitations; (3) Best Management Practices (BMPs) and their use to control small volume spills and releases of SBF; (4) the proposal's engineering and economic modeling parameters; and (5) procedural and definition issues. EPA evaluated all of these issues based on additional information collected by EPA or received during the comment period. EPA then discussed the results of these evaluations in a Notice of Data Availability which is discussed below.

E. Notice of Data Availability

On April 21, 2000 (65 FR 21548), EPA published a Notice of Data Availability (NODA) to present a summary of new data received in comments on the proposed rule or collected by EPA following publication of the proposal. In the April 2000 NODA, EPA discussed the major issues and presented several revised modeling and alternative approaches to address these issues. EPA solicited comment on the data collected since proposal and on the revised modeling and alternative approaches to manage SBF discharges.

III. Summary of Data and Information Received in Response to the Notice of Data Availability

The April 2000 NODA summarized the data and information received by EPA in response to the February 1999 proposal and information received before the April 2000 NODA. This section describes the data received by EPA in response to the April 2000 NODA.

A. Pollutant Loading and Numeric Limit Analyses

1. SBF Retention on Cuttings

SBF retention on cuttings (ROC) data quantify the amount of SBF retained on cuttings (mass of SBF/mass of wet cuttings, expressed as a percentage). Lower ROC values indicate less SBF retained on cuttings. EPA uses ROC data, along with other engineering factors (

e.g.,

installation requirements, fluid rheology) to evaluate the

performance of various solids control technologies.

In response to the February 1999 proposal, industry submitted data for SBF ROC from 36 wells. EPA determined that 16 files were complete and accurate, and these data were presented in the April 2000 NODA. EPA rejected six files due to incomplete reporting. EPA received 14 files too late for inclusion in the April 2000 NODA analyses.

In response to the April 2000 NODA, EPA received and evaluated ROC data from an additional 79 SBF wells: the 14 received after the February 1999 proposal comment period; 27 additional sets received during the April 2000 NODA comment period; and 38 received after the April 2000 NODA comment period. EPA determined that data from 49 of these 79 wells were complete for inclusion in the final rule analyses. Therefore, EPA used data from 65 wells to determine the ROC performance of the various solids control technologies. The collection, engineering review, and extraction of data from these files are described in the SBF Development Document.

EPA revised the average ROC values of various solids control technologies based on the final ROC data. These revised average ROC values were combined to yield the average ROC value for the following three SBF-cuttings technology options: (1) BAT/NSPS Option 1 is based on the use of shale shakes, cuttings dryer, fines removal unit, and discharges from the cuttings dryer and fines removal unit and has a long-term average ROC value of 4.03%; (2) BAT/NSPS Option 2 is based on the use of shale shakes, cuttings dryer, and fines removal unit, and one discharge from the cuttings dryer, and has a long-term average ROC value of 3.82%; and (3) BAT/NSPS Option 3 is based on the use of shale shakes, cuttings boxes, barges, and zero discharge land disposal and offshore re-injection and has a long-term average ROC value of 10.2%. In addition, using the ROC data, EPA developed a BAT limitation and standard controlling the base fluid retained on cuttings for drilling fluids with the environmental performance of esters (

e.g.,

biodegradation, sediment toxicity). EPA developed this option to provide operators an incentive to use ester-based SBFs and has a long-term average ROC value of 4.8%. EPA used the ROC data to establish a BAT limitation and a NSPS on base fluid retained on cuttings. The base fluid retained on cuttings limitation and standard both incorporate the variability of solids control efficiencies and are higher than the long term average.

2. Days to Drill

EPA uses the number of days to drill the SBF interval, for all four model wells, as an input parameter in the NWQI and cost analysis. EPA extracted relevant data from each of the 65 wells identified above to estimate the number of days to drill each of the four model well SBF intervals (Docket No. W-98-26, Record No. IV.B.a.7). The revised numbers of days required to drill the SBF model wells are based on a revised average rate of SBF-cuttings generation (

i.e.,

108.7 bbls wet cuttings/day). The revised numbers of days required to drill the SBF model wells are: (1) 5.2 days for shallow-water development wells (SWD); (2) 10.9 days for shallow-water exploratory wells (SWE); (3) 7.9 days for deep-water development wells (DWD); and (4) 17.5 days for deep-water exploratory wells (DWE).

3. Well Count Projections Over Next Five Years

EPA revised well count projections for Offshore GOM, Offshore California, and Cook Inlet, AK, based on information submitted by industry (Docket No. W-98-26, Record No. IV.B.a.9; Record No. IV.B.a.10; Record No. IV.B.a.11). The revised annual well counts are 1,047 shallow water wells and 138 deep water wells in Offshore GOM; 7 shallow water wells and no deep water wells in Offshore California; and 6 shallow water wells and no deep water wells in Cook Inlet, AK. These revised well counts are not significantly different from the well counts used in the February 1999 proposal and April 2000 NODA (

i.e., see

SBF Proposal Development Document (EPA-821-B-98-021), Table IV-2: 1,022 shallow water wells and 139 deep water wells across the GOM, Offshore California, and Cook Inlet, AK).

Industry only provided the well counts in terms of shallow water versus deep water wells. EPA further divided the revised well counts into development and exploratory well category counts for estimating pollutant loadings, compliance costs, and NWQIs. EPA performed this allocation using prior well count data from the April 2000 NODA. EPA derived percentages of development versus exploratory wells for both shallow water well types and deep water well types. EPA then applied these percentages to the revised aggregated shallow water and deep water well counts provided by industry. EPA also collected additional washout rates for WBF and SBF drilling.

EPA also revised well count projections to reflect enhanced directional drilling capabilities when using SBF. EPA received information that SBF directional drilling can reduce the number of wells required to drill a development well project. Specifically, industry stated that SBF development drilling can generally reduce the drilled footage required for full development of a typical reservoir by one-third as compared with WBF drilling (Docket No. W-98-26, Record No. IV.B.a.9). EPA has included this consideration by reducing the footage drilled by one-third for WBF development wells projected to convert from WBF to SBF under the two controlled discharge options.

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

For the February 1999 proposal and April 2000 NODA, EPA estimated that 80% of the average annual GOM wells are drilled using WBF exclusively; 10% are drilled with SBF; and 10% are drilled with OBF. EPA also included in well counts estimates of operators converting from OBF to SBF or SBF to OBF under each of the SBF-cuttings controlled discharge options.

For the final rule, EPA revised the relative frequency of use between WBF, OBF, and SBF under the two discharge options and the zero discharge option based on data submitted by industry (Docket No. W-98-26, Record No. IV.B.a.9; Record No. IV.B.a.10; Record No. IV.B.a.11). Industry supplied this information to EPA in several formats. EPA used the most reliable information (

e.g.,

the actual well count data for WBF, OBF, and SBF wells over a period of three years) to estimate drilling fluid use under each of the SBF-cuttings control options (

see

SBF Development Document).

EPA believes that some operators would switch from WBFs to SBFs for certain wells due to the increased efficiency of SBF drilling. While no good industry average statistics exist, it is generally considered that SBFs reduce overall drilling time by 50% (

e.g.,

if a well took 60 days to drill with WBF, the same well should be able to be drilled with SBF in 30 days) (Docket No. W-98-26, Record No. IV.B.a.9; Record No. IV.B.a.10; Record No. IV.B.a.11). Reducing drilling time generally reduces drilling costs. However, not all drilling operators will switch from WBFs to SBF due to a variety of other factors, (

e.g.,

WBFs are less expensive (per barrel) than SBFs, potential for lost circulation downhole).

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

SBFs to OBFs but that some operators would switch to WBFs. Some drilling operations require the technical performance of non-aqueous drilling fluids and operators must select either an OBF or SBF. Therefore, for these drilling operations, operators would select OBFs in place of SBF under the SBF-cuttings zero discharge option as OBFs are less expensive (per barrel) than SBFs. However, some drilling operations could use either WBFs or oleaginous drilling fluids such as OBFs, enhanced mineral oil based drilling fluids, or SBFs. Depending on a variety of site specific factors (

e.g.,

formation characteristics, directional drilling requirements, torque and drag requirements), operators may select WBFs in lieu of SBFs or OBFs under the SBF-cuttings zero discharge option.

5. Waste Volumes and Characteristics

EPA collected additional data to identify the volumes and characteristics of WBF discharges. This additional data more adequately describes the total amount of pollutants loadings and NWQI under each of the three SBF-cuttings management options. For example, under the SBF zero discharge option (BAT/NSPS Option 3) operators would more likely choose WBF and OBF over SBF due primarily to the relatively higher unit cost of SBF.

Different pollutant loadings and NWQI are expected for WBF as compared with either OBF or SBF wells based on differences in washout and length of drilling time. EPA anticipates a reduction in cuttings waste volume when comparing SBF-drilling to WBF-drilling based on greater hole washout (

i.e.,

enlargement) in WBF drilling. Industry estimated that WBF washout percentages vary between 25% and 75%, with 45% being an acceptable average and confirmed EPA's SBF and OBF washout percentage of 7.5% as appropriate (Docket No. W-98-26, Record No. IV.B.a.9).

For the final rule, EPA also estimated that the barite used in SBF drilling is nearly pure barium sulfate (

i.e.,

BaSO

4

) and, by gravimetric analysis, calculated the weight percentage of barium in barite as 58.8%.

B. Compliance Costs Analyses

1. Equipment Installation and Downtime

For the April 2000 NODA, projected compliance costs for all options included equipment installation and downtime for each SBF well drilled. After further review of ROC data wells (

see

Section III.A), EPA modified this parameter in the final analyses to reflect current practice of drilling multiple wells per year for any one equipment installation (Docket No. W-98-26, Record No. IV.B.a.9). EPA reviewed the ROC well data for the frequency of multiple wells on specified structures. EPA used the resulting well-per-structure analysis to adjust projected annual SBF compliance costs by including the consideration of drilling more than one SBF well per equipment installation per year. EPA estimated that 2.2 development wells per structure and 1.6 exploratory wells per structure are current industry practice, based on industry-submitted data (

see

SBF Development Document).

EPA received information on the ability of operators to install cuttings dryers (

e.g.,

vertical or horizontal centrifuges, squeeze press mud recovery units, High-G linear shakers) on existing GOM rigs (Docket No. W-98-26, Record No. IV.B.b.33). While some industry sources filed timely comments alleging that some rigs could not accommodate additional solids control equipment, in late comments, industry provided data concerning the number of GOM rigs in operation which are not capable of having a cuttings dryer system installed due to either rig space and/or rig design without prohibitive costs or rig modifications.

EPA also received information on a new cuttings containment, handling, and transfer equipment system. The new system is designed to eliminate the need to use cuttings boxes to handle cuttings. EPA received information from one operator that recently field tested the cuttings transfer system on one 12

1/4

inch well section in the North Sea. The operator contained 100% of the cuttings on a rig (Alba) with limited deck space. Cuttings were handled in bulk below deck and pumped directly onto a waiting vessel for eventual land disposal. The operator estimated that use of the new cuttings transfer system eliminated hundreds of crane lifts and manual handling issues and thereby improved worker safety.

2. Current Drilling Fluid Costs

In response to the April 2000 NODA, EPA revised unit costs of WBF, OBF, and SBF. Based on industry data, EPA used the WBF unit cost of $45 per barrel for the final rule. The February 1999 Proposal and April 2000 NODA used OBF and SBF unit costs of $75 and $200 per barrel of drilling fluid, respectively. Industry data indicates a range of OBF unit costs from $70-$90 per barrel and EPA used the OBF unit cost of $79 per barrel for the final rule. EPA estimates that SBF unit costs will remain between $160 to $300 per barrel of drilling fluid over the next few years. EPA used an SBF unit cost of $221 per barrel of drilling fluid for the final rule based on the most frequently used SBF in the offshore market.

3. Cost Savings of SBF Use as Compared With WBF Use

EPA revised its compliance costs to include the following factors: (1) The cost savings associated with increased rate of penetration when using SBF as compared to WBF; and (2) the cost of lost WBFs that are discharged while drilling. EPA also examined, but did not include in its final compliance cost impacts, the costs associated with projected failures of a fraction of WBF wells to meet sheen or toxicity limitations, including costs of meeting zero discharge from these wells. EPA used this data to examine compliance costs impacts if operators switch from SBF to WBF drilling, or vice versa.

EPA requested data from industry on rate of penetration (ROP) for WBF operations as compared to SBF operations. Industry stated that ROP values of 300 feet per hour for SBF (and OBF) operations and 150 feet per hour for WBF are reasonable averages. However, using these values over an entire well was not recommended “due to the large number of variables” (Docket No. W-98-26, Record No. IV.B.a.9). Industry's information further states that a generally-accepted estimate is that “SBFs reduce overall drilling time by 50%” (Docket No. W-98-26, Record No. IV.B.a.9).

4. Construction Cost Index

EPA used the Construction Cost Index (CCI) from the Engineering News and Record (

see

http://www.enr.com/cost/costcci.asp) to reflect costs in 1999 dollars rather than 1998 dollars as was used for the April 2000 NODA. EPA used a CCI factor of 1.108 to reflect 1999 dollars and a base year of 1995.

C. Economic Impacts Analyses

For the final rule, EPA obtained and used MMS data on drilling through 1999 to identify any new firms operating in the offshore GOM and determine which firms were involved in deep water drilling operations. EPA identified 17 additional firms newly drilling in the GOM, of which 2 were identified as drilling in deep water. Of the new firms, 7 were identified as or assumed to be (for lack of data) small entities. One of these seven small firms was identified as a small entity drilling in deep water. This latter firm drilled two wells in the deep water in 1999.

EPA collected 1999 financial information on number of employees,

assets, equity, revenues, net income, return on assets, return on equity, and profit margin for the publicly held, newly identified firms. EPA also updated financial information for the publicly held firms identified in February 1999 proposal SBF Economic Analysis (EPA-821-B-98-020).

EPA also collected information on 13 GOM onshore sites where offshore oil and gas drilling waste is handled or disposed. This information consists of precise geographical location, amount of waste handled annually, and site capacity. This information was provided to EPA Region 6 for use in its environmental justice (EJ) computer model to screen for sites (

i.e.,

Tier 1 analysis) where disposal of additional drilling wastes under a zero discharge option might have environmental justice implications. EPA Tier 1 analyses identified that five of the thirteen onshore facilities warranted additional review.

D. Water Quality Impact and Human Health Analyses

In response to April 2000 NODA comments and information, EPA revised the water quality and human health analyses for the final rule based on: (1) Information on seabed surveys; (2) revised fish consumption rates; (3) information on Alaska state water quality standards; and (4) revised ROC data which affect EPA modeling of water quality, sediment quality, and human health impacts.

1. Seabed Surveys

EPA received public comments regarding the impact of SBF discharges on the benthic environment. Several seabed surveys were submitted to EPA together with the public comments. Information from two comments contained specific seabed survey data on sediment SBF concentrations after discharge of SBF cuttings. EPA included additional data from six wells in the calculation of mean SBF sediment concentration (at 100 meters from the modeled discharge) used in the water quality analysis. The mean SBF sediment concentration changed from 14,741 mg/kg as published in the April 2000 NODA to 9,718 mg/kg for modeled Gulf of Mexico wells and from 8,655 mg/kg to 13,052 mg/kg for wells modeled in Offshore California and Cook Inlet, Alaska.

EPA also received information on the on-going joint Industry/MMS GOM seabed survey. The Industry/MMS workgroup completed the first two cruises of the four cruise study in time for EPA's consideration for this final rule. Cruise 1 was a physical survey of 10 GOM shelf locations, with the objective of detection and delineation of cuttings piles using physical techniques. Cruise 2 was to scout and screen the final 5 shelf and 3 deep water GOM wells chosen for the definitive study where SBF were used. The SBF-cuttings discharges included either internal olefins or LAO/ester blends. Both cruises did not detect any large mounds of cuttings under any of the rigs or platforms. Remotely operated vehicles (ROV) using video cameras and side-scanning sonar were used to conduct the physical investigations on the seabed. Video investigations only detected small cuttings clumps (<6″) around the base of some of the facilities and 1″ thick cuttings accumulations on facility horizontal cross members. Outside of a 50-100′ radius from the facility, no visible cuttings accumulations (large or small) were detected at any of the facility survey sites.

Finally, EPA received a report prepared for the MMS which provided a review of the scientific literature and seabed surveys to determine the environmental impacts of SBFs (Docket No. W-98-26, Record No. IV.F.1). The literature report confirms EPA's position that benthic communities will recover as SBF concentrations in sediments decrease and sediment oxygen concentrations increase. The report also confirms EPA's position that within three to five years of cessation of SBF-cuttings discharges, concentrations of SBFs in sediments will have fallen to low enough levels and oxygen concentrations will have increased enough throughout the previously affected area that complete recovery will be possible.

2. Fish Consumption Rates

EPA revised the fish consumption rates for use in environmental assessment analyses. The consumption rates vary depending on the fish habitat location (

i.e.,

freshwater, estuarine, and marine). EPA used the marine only fish consumption rate for the finfish consumption health risk analysis for the Gulf of Mexico and Offshore California. EPA used the estuarine/marine consumption rate for the Cook Inlet, Alaska analysis. EPA used the estuarine/marine consumption rate for all regions in the shrimp consumption health risk analysis.

EPA also conducted an investigation into the environmental factors affecting Native subsistence foods in Cook Inlet. EPA has incorporated relevant information from this investigation into the SBF Environmental Assessment.

3. State Water Quality Standards

EPA evaluated the potential decrease of water quality from the regulatory discharge options and compared the pollutant concentrations to recommended Federal water quality criteria. For discharges occurring in Cook Inlet, Alaska, EPA also compared the receiving water quality to Alaska state water quality standards. EPA used the updated Alaska state standards for the water quality analysis for Cook Inlet, Alaska.

E. Non-Water Quality Environmental Impact Analyses

EPA received additional data affecting the NWQI analyses in response to the April 2000 NODA. These data include additional information on retention on cuttings and information regarding offshore injection and onshore disposal practices for each of the three geographical areas: Gulf of Mexico, Offshore California, and Cook Inlet, Alaska.

EPA revised the average SBF retention on cuttings for the discharge options based on additional ROC data. Revisions in ROC data affect the volume of SBF-cuttings generated. Consequently, EPA revised the amount of SBF-cuttings that will need to be treated under the two SBF-cuttings controlled discharge options (

e.g.,

BAT/NSPS Options 1 and 2). EPA also revised: (1) The amount of SBF-fines that will need to be re-injected on-site or hauled to shore for disposal under one of the SBF-cuttings controlled discharge option (

e.g.,

BAT/NSPS Option 2); and (2) the amount of SBF-fines and SBF-cuttings re-injected on-site or hauled to shore for disposal under the zero discharge option (BAT/NSPS Option 3).

EPA received additional SBF well interval data which was used to re-calculate the number of days to drill the model SBF wells (

see

Section III.B.). For the NWQI analyses, the number of days to drill the model wells serves as the basis for estimating the length of time equipment will be used to either treat the cuttings before discharge or the hauling requirements under the zero discharge option. The EPA NWQI models estimate that air emissions and fuel use rates increase when the time required to complete a model well also increases.

EPA obtained information regarding the current practice of zero discharge disposal for each of three geographic areas, Gulf of Mexico, Offshore California, and Cook Inlet, Alaska (

see

Section IV.D). Current practice indicates that most of the waste generated in the Gulf of Mexico and Offshore California

and brought to shore is injected onshore, whereas all of the waste currently generated in Cook Inlet is injected offshore at the drilling site or at a near-by Class II Underground Injection Control (UIC) disposal well. EPA also received from an on-shore injection facility specific equipment information, including the cuttings injection rate and cuttings grinding and injection equipment power requirements and fuel rates (Docket No. W-98-26, Record No. IV.D.2).

Industry provided EPA with information regarding SBF use (

see

Section III.A). One operator (Unocal) stated that it is starting to use SBF to drill the entire well and not just intervals in which WBFs present problems because drilling time can be significantly reduced. EPA incorporated this information into the NWQI analyses by estimating the reduction of impacts when using SBFs instead of WBFs. EPA also received during the April 2000 NODA comment period information related to the average increase in drilling time (1.5 days) in order to comply with zero discharge (Docket No. W-98-26, Record No. IV.A.a.3).

F. Compliance Analytical Methods

EPA completed additional studies in response to the April 2000 NODA to support the development of analytical methods for determining sediment toxicity, biodegradation, and oil retention on cuttings. For sediment toxicity and biodegradation, EPA focused specifically on optimizing test conditions (

e.g.,

test duration, sediment composition), discriminatory power, reproducibility, reliability, and practicality. EPA's sediment toxicity study provided toxicity data for both pure base fluids and standard mud formulations of these base fluids. EPA's biodegradation study evaluated the degradation of pure base fluids as determined by the solid phase test. For oil retention on cuttings, EPA conducted studies to verify and document the sensitivity of the retort test method.

During this same time period, industry sponsored Synthetic Based Muds Research Consortium (SBMRC) conducted parallel studies on the same three parameters (

i.e.,

sediment toxicity, biodegradation, and base fluid retention on cuttings). For sediment toxicity, industry provided extensive data comparing a 4-day versus a 10-day test duration, natural versus synthetic sediments, as well as toxicity data on both pure base fluids and mud formulations of these base fluids. For biodegradation, industry submitted results from the closed bottle and respirometry tests for biodegradation in addition to the solid phase test. For oil retention on cuttings, Industry and EPA conducted rig-based method detection limit studies.

IV. Summary of Revisions Based on Notice of Data Availability Comments

A summary of significant revisions to the analyses made by EPA in response to the February 1999 proposal is provided in the April 2000 NODA (

see

65 FR 21549, Sections III and IV). This section describes the revisions to the analyses since publication of the April 2000 NODA.

A. Pollutant Loading Analyses

1. Loadings for Water-Based Drilling Fluids and Cuttings

For the final rule, EPA included the pollutant reductions (or increases) of the technology options based on operators switching from OBFs or WBFs to SBFs (or vice versa) and used data contained in the Offshore Development Document (EPA-821-R-93-003). Waste volume and/or pollutant loading data, on use of OBFs and WBFs presented in the Offshore Development Document, were expressed on a “per bbl,” “per well,” or a “per day” basis. Data from the Offshore rule record included: (1) WBF composition; (2) waste volumes for WBFs, OBFs, and associated cuttings; (3) the frequency of mineral oil use in WBF operations; and (4) the expected permit limitation failure rates (primarily for toxicity) on mineral oil fluids resulting in the requirement to haul or inject these wastes). These data then were applied to the current, revised well count projections and/or projected waste volumes to estimate discharge option loadings and the amount of OBFs, WBFs, and associated cuttings that require zero discharge under existing regulations (

e.g.,

OBFs containing diesel oil, WBFs that fail the SPP Toxicity Test). The Offshore Development Document provided information relevant to the inclusion of WBFs in the final analyses including: (1) Frequency of WBFs that failed permit limitations (Tables XI-10 and XI-7); (2) the composition of WBFs (Tables XI-3 and XI-6); (3) mineral oil composition (Table XI-5); and (4) the composition of cuttings from WBF (Section XI.3.4).

Industry-wide, regional, and total loadings were calculated for the loadings analyses for this final rule from the revised well counts provided by industry (Docket No. W-98-26, Record No. IV.B.a.9; Record No. IV.B.a.10; Record No. IV.B.a.11) combined with composition and estimated discharge volumes for WBFs (Offshore Development Document, Table XI-2).

In the final loadings analyses, EPA also corrected an error in the loading model used for the April 2000 NODA analyses. The error related to how EPA estimated the volume of fines from the fines removal unit captured and not discharged under BAT/NSPS Option 2. The volume of fines is based on many factors including the hole size, washout, and the percentage of the total wet cuttings produced from the solids control system that are fines. EPA incorrectly used the volume of dry cuttings per model well in the April 2000 NODA loading model to estimate the volume of fines generated from the BAT/NSPS Option 2 solids control system. The final loadings model correctly uses the volume of wet cuttings per model well to estimate the volume of fines generated from the BAT/NSPS Option 2 solids control system. The correction of the error had the effect of increasing the amount of fines captured for zero discharge under BAT/NSPS Option 2.

2. Drilling Fluid and Cuttings Composition and Density

The density of drilling wastes hauled in California was revised from 704 to 716 pounds per barrel to reflect the current density derived from the weight and volume data in the revised loadings model. This results in a change in the unit cost to haul waste in California to $12.53 and $5.89 per barrel for disposal and handling costs, respectively.

3. Days to Drill

EPA revised the number of drilling days based on data submitted in response to the April 2000 NODA for each of the four model well types. The number of drilling days input parameter affects NWQI and compliance costs (

e.g.,

equipment rental costs).

4. Directional Drilling

EPA also received additional data concerning the performance of SBF versus WBF for directional drilling operations (Docket No. W-98-26, Record No. IV.B.a.9). EPA used this information, the reduced number of wells and total footage of SBF-drilled development wells, to estimate pollutant loading reductions resulting from WBF to SBF conversions. For each of the two SBF-cuttings controlled discharge options (

i.e.,

BAT/NSPS Option 1 and 2), this revision reduced the annual sum total of discharged WBF and WBF-cuttings.

B. Compliance Cost Analysis

1. Costs of WBF

As stated above, EPA modified the cost analysis for the final rule to include WBF cost factors. The WBF cost factors that EPA considered include: (1) The cost of discharged WBFs and WBF associated with cuttings discharged onsite; (2) the projected occurrence of mineral oil spots and/or lubrication and the projected failure rate of these mineral oil-amended fluids to meet permit limitations on toxicity and subsequent requirement to re-inject these materials down hole or haul them for onshore disposal; and (3) the rig costs associated with increases or decreases of drilling time related to WBF-to-SBF or SBF-to-WBF conversions over the projected interval of SBF use.

The volumes of discharged WBF and associated cuttings were estimated on a per well basis from data contained in the Offshore Development Document (EPA-821-R-93-003) for Gulf of Mexico, California, and Cook Inlet, AK wells. A weighted average discharge volume for each region, based on volumes projected for shallow wells and deep wells and the projected number of wells for each, was derived to estimate the volume of fluids and cuttings discharged onsite, per well, from WBF operations. (

Note:

In the Offshore Development Document “shallow” and “deep” refer to well depth, and are not the same as “shallow” water and “deep” water wells which refer to water depth in this final rule.) The volume of adhering WBF on discharged cuttings, as contained in the Offshore Development Document, was estimated at 5% of the total cuttings volume. The costs for these discharged WBFs were then calculated from a per barrel estimate of average WBF cost. These per well costs were then applied to the well count data in this final rule to derive aggregate regional and total costs. Also, to assess lost fluid costs over the projected SBF drilling interval, for the zero discharge option, the average discharge volumes per well were recalculated as average discharge volumes per day, based on the assumed number of days (

i.e.,

20 days) used in the Offshore Development Document for drilling WBF wells.

The projected incidences of WBF with mineral oil spots, mineral oil lubrication, or both mineral oil spot and lubrication were based on the Offshore Development Document estimates of the percentages of projected wells in each region, projected shallow water versus deep water wells, and the projected incidence of spotting and lubrication. These percentages were then applied to current well count data for this final rule. EPA used the Offshore Development Document rates of failure (

i.e.,

exceeding permit toxicity limitations) to project the current number of wells that would require onsite injection or onshore disposal of mineral oil-amended WBF, and their disposal volumes were calculated from per well volume estimates for WBF wells.

The effect of WBF-to-SBF conversion (anticipated under the discharge options) and SBF-to-WBF conversion (anticipated under the zero discharge option) were derived from the estimated duration (in days) of the SBF-drilled interval. The projected number of drilling days was increased by a factor of 2 for each WBF model well to derive the projected number of drilling days that would be required if WBFs were used in place of SBFs. The incremental drilling time was used to estimate compliance costs (

e.g.,

increased rig costs) associated with SBF-to-WBF conversions.

2. Equipment Installation and Downtime

In the April 2000 NODA, EPA estimated that each SBF well incurred cuttings dryer installation and downtime costs. EPA revised the number of SBF wells drilled per cuttings dryer equipment installation per year based on industry-supplied ROC data (

see

Section III.B.1). EPA concluded that operators are drilling multiple wells per year with the same cuttings dryer equipment installation. Consequently, EPA reduced the number of cuttings dryer equipment installations required to drill the annual number of SBF wells. For development wells, the average number of SBF wells drilled per cuttings dryer equipment installation per year is 2.2. For exploration wells, the average number of SBF wells drilled per cuttings dryer equipment installation per year is 1.6. EPA incorporated these factors into the compliance costs estimates and these factors reduced the overall cuttings dryer equipment installation and downtime costs for the industry.

3. Proportion of Hauled Versus Injected Wastes

EPA estimated in the April 2000 NODA that 80% of drilling operations in the GOM, Offshore California, and Cook Inlet, Alaska, haul waste onshore with the remaining 20% re-injecting these wastes onsite. EPA used these proportions to weight the average cost of complying with zero discharge (

i.e.,

BAT/NSPS Option 3). EPA revised these proportions based on additional information received in response to the April 2000 NODA (

see

Section IV.E below) and updated the compliance cost and NWQI models.

4. OBF and WBF Conversion to SBF

EPA revised its compliance cost model to incorporate the effect of operators switching from one type of drilling fluid to another under each of the three SBF-cuttings technology options (

see

Section III.A.4). Generally, as compared with WBF and OBFs, SBFs led to a reduction in days required to drill a model well which leads to a decrease in drilling costs. Additionally, EPA revised the development drilling footage estimate due to additional information on the improved directional drilling capabilities of SBF over WBF.

C. Economic Impacts Analyses

In response to the April 2000 NODA, EPA identified that two projects used for economic modeling have shut in. Consequently, EPA removed these two projects from the economic analysis. A total of 18 projects remain for the economic modeling of existing projects and 13 remain for the economic modeling of new projects.

EPA added an environmental justice (EJ) analysis which investigates the potential for impacts on minorities and socioeconomically disadvantaged groups under the zero discharge option. EPA performed a Tier 1 screening analysis, which combines geographic location and U.S. Census Bureau data to determine the number of persons living within 1 mile and 50 miles of drilling waste handling and disposal sites, their race, and their socioeconomic status. A computer program developed by EPA Region 6 was used to rank and characterize sites on the basis of whether the populations near the site contain higher proportions of minority and socioeconomically disadvantaged persons than the state as a whole. Based on scores derived for the 13 GOM onshore drilling waste handling and disposal sites, EPA identified five facilities that could be potentially associated with disproportionate impacts on minorities or socioeconomically disadvantaged groups. EPA presents the results of the EJ analysis in Section IX.

D. Water Quality Impact and Human Health Analyses

EPA received comments regarding the heavy metal leach factors used in the water quality impact analyses but did not receive any specific data that could be used in the analyses (Docket No. W-98-26, Record No. IV.A.a.2). EPA

therefore did not change these factors. However, EPA reevaluated the modeling used in the proposal that metals for which there were no factors found in the literature were completely insoluble in the receiving water (

i.e.,

the leach factor would be zero). EPA estimated that these heavy metals would not be less soluble than iron which has the lowest leach percentage factor. Thus, the iron leach factor was transferred to the following metals for which a zero leach factor was previously used: aluminum, antimony, beryllium, selenium, silver, thallium, tin, and titanium.

E. Non-Water Quality Environmental Impact Analyses

As mentioned in Section III.E, EPA received additional information regarding waste disposal practices in each of the three geographic areas (

e.g.,

GOM, Offshore California, Cook Inlet, Alaska). As a result of this information, EPA revised the modeling for the fraction of waste either injected at the drill site, injected on-shore or land disposed (

see

SBF Development Document). Though the percentage of waste injected onsite versus hauled to shore (20% vs. 80%) in the GOM remains unchanged, the method of onshore disposal has been revised for the final rule. In the GOM, 80% of the waste hauled to shore is injected onshore and only 20% is landfarmed.

EPA estimates that all SBF wastes from Californian deep water exploratory wells are sent onshore (

i.e.,

100% onshore disposal vs. 0% on-site injection). For all other wells (

i.e.,

shallow water development and exploratory and deep water development), EPA estimates that most of the offshore waste is disposed through offshore on-site cuttings re-injection (

i.e.,

20% onshore disposal vs. 80% on-site injection) based on the fact that most of these wells are being drilled from fixed facilities. EPA estimates that most California offshore wastes sent onshore are disposed via onshore formation injection (

i.e.,

20% of offshore wastes sent onshore disposed via landfarming vs. 80% of offshore wastes sent onshore disposed via onshore injection) based on the number of California land disposal operations.

At proposal, based on the record for the 1996 Coastal rule, EPA determined that onsite injection was not feasible throughout Cook Inlet, Alaska (

see

Coastal Development Document, EPA-821-R-96-023, Section 5.10.3). More recently, however, EPA identified in the April 2000 NODA (65 FR 21558) that the SBF rule record now demonstrates that many Cook Inlet operators in Coastal waters are using cuttings re-injection (

see

Docket No. W-98-26: Record No. III.B.a.11, Record No. III.B.a.23, Record No. III.B.a.53). EPA contacted Cook Inlet operators (

e.g.,

Phillips, Unocal, Marathon Oil) and the State regulatory agency, Alaska Oil and Gas Conservation Commission (AOGCC), for more information on the most recent re-injection practices of Coastal and Offshore Cook Inlet operators (65 FR 21558). AOGCC regulations provide Cook Inlet operators the opportunity to permit and operate Class II disposal wells and annular disposal activities. Information provided to EPA indicate that Cook Inlet operators in Coastal waters are availing themselves of on-site cuttings injection and are receiving AOGCC permits for this activity. Generally, Cook Inlet operators in Coastal waters agree that on-site injection is available for most operations.

AOGCC also agreed that there should be enough formation re-injection disposal capacity for the small number of wells (< 5-10 wells per year) being drilled in Cook Inlet Coastal waters. AOGCC stated, however, that case-specific limitations should be considered when evaluating disposal options. For instance, Unocal has experienced difficulty establishing formation injection in several wells that were initially considered for annular disposal. In addition, Cook Inlet operators have the burden of proving to AOGCC's satisfaction that the waste will be confined to the formation disposal interval. Approval of annular disposal includes a review of cementing and leak-off test records. In some instances the operator may also have to run a cement bond log. When an older well is converted for use as a disposal well, some of this information may not exist. In cases where there is insufficient information, disposal is not allowed. Annular disposal is also limited to the facility on which the waste is generated. Although Class II disposal regulations don't restrict waste transport, it has generally been the practice of the various fields' owners not to accept any waste generated by other operators. In addition, AOGCC stated that a zero discharge requirement poses serious technical hurdles with respect to the handling of drilling waste for exploration drilling with mobile rigs. Normally, there is neither capacity for storage or room for processing equipment on exploratory drilling rigs. Therefore, to be conservative for the NWQI analysis, EPA estimates that all of the cuttings from the Coastal Cook Inlet operations (

i.e.,

shallow water wells) are re-injected (

i.e.,

0% onshore disposal vs. 100% on-site injection) based on the ability of industry to dispose of oil-based cuttings via on-site formation injection after gaining State regulatory approval.

In order to assess the SBF NWQIs relative to the total impacts from drilling operations, EPA included estimates of the daily drilling rig impacts to the NWQIs from SBF-related activities. The additional impacts consist of fuel use and air emissions resulting from the various drilling rig pumps and motors as well as impacts of a daily helicopter trip for transporting personnel and/or supplies. Impacts were assessed for the number of days that an SBF interval is drilled versus the number of days well intervals are drilled using WBFs and OBFs and for the number of wells drilled using each of the drilling fluids.

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

A series of potential numerical limits for retention of SBF base fluid on SBF-cuttings were developed based in part on combinations of data selection criteria suggested in comments on the April 2000 NODA. These data selection criteria include: (1) Existing record of retention calculations (

i.e.

, “back-up” retort sheet information for quality assurance/quality control purposes); and (2) foreign or domestic location of well drilling activity (

e.g.,

North Sea, Canada). Numerical limits promulgated in today's final rule were based on data with existing records of retention calculations, and they included data from well drilling activities in foreign countries. The inclusion of data from foreign countries is intended to include data representing drilling with cuttings dryers at a wider range of geological formations than just the ones for which data was received from current operations.

V. Development and Selection of Effluent Limitations Guidelines and Standards

A. Waste Generation and Characterization

Drill cuttings are produced continuously at the bottom of the hole at a rate dependent on a variety of factors including: (1) The advancement of the drill bit; (2) the size and design of drill bit used (

e.g.,

polycrystalline diamond compact (PDC)); and (3) the drilling fluid type used. Drill cuttings are carried to the surface by the drilling fluid, where the cuttings are separated from the drilling fluid by the solids control system. The drilling fluid is then

sent back to the active mud system (

e.g.,

mud pumps, down hole, trip tanks, etc.), provided it still has characteristics to meet technical requirements. Drilling fluids cool and lubricate the drill bit, stabilize the walls of the borehole, transport cuttings, and maintain equilibrium between the borehole and the formation pressures. Various sizes of drill cuttings are separated by the solids separations equipment, and it is necessary to remove the fines (

i.e.,

small sized cuttings or “low gravity solids”) as well as the large cuttings from the drilling fluid to maintain the required rheological properties.

Increased recovery from the cuttings is more problematic for WBF than for SBF because the WBF water-wets the cuttings which encourages the cuttings to disperse and spoil the drilling fluid properties. Therefore, compared to WBF, more aggressive methods of recovering SBF from the cuttings wastestream are practical.

SBFs, used or unused, are a valuable commodity and not a waste. It is industry practice to continuously reuse the SBF while drilling a well interval, and at the end of the well, to ship the remaining SBF back to shore for refurbishment and reuse. One of the main incentives for operators to attempt to recover as much SBF as possible during drilling is the relatively high unit cost of SBF, approximately $160 to $300 per barrel, as compared to OBFs ($70 to 90 per barrel) and WBFs ($45 per barrel) (Docket No. W-98-26, Record No. IV.B.a.13). Operators involved in the first 1998 GOM field demonstrations of cuttings dryers (

i.e.,

advanced solids control technology) were attempting to obtain further reductions in drilling costs, beyond that obtained by shortening the overall drilling time for the well, by recovering more SBF. SBFs are relatively easy to separate from the drill cuttings because the drill cuttings do not disperse or hydrate in the drilling fluid to the same extent as compared to WBFs. Reducing cuttings hydration is particularly important in certain formations (

e.g.,

shale formations in GOM). With WBF, due to dispersion of the drill cuttings, drilling fluid components often need to be added to maintain the required drilling fluid properties. These additions are often in excess of what the drilling system can accommodate. The excess “dilution volume” of WBF is a resultant waste. This dilution volume waste does not occur with SBF. For these reasons, SBF is only discharged as a contaminant of the drill cuttings wastestream. It is not discharged on purpose as neat drilling fluid (

i.e.,

drilling fluid not associated with cuttings).

Current practice is that the top well section is normally drilled with a WBF. As the well becomes deeper, the performance requirements of the drilling fluid increase, and the operator may, at some point, decide that the drilling fluid system should be changed to either a traditional OBF, based on diesel oil or mineral oil, or an SBF. The system, including the drill string and the solids separation equipment, must be changed entirely from the WBF to the SBF (or OBF) system, and the two do not function as a blended system. The entire system is either: (1) A water dispersible (aqueous) drilling fluid such as a WBF; or (2) an oleaginous drilling fluid such as OBFs, enhanced mineral oil based drilling fluids, or SBFs. The decision to change the system from a WBF water dispersible system to an oleaginous drilling fluid depends on many factors including:

I. The operational considerations (

e.g.,

rig type, risk of riser disconnects, rig equipment, and distance from support facilities);

II. The relative drilling performance of one type fluid compared to another (

e.g.,

rate of penetration, well angle, hole size/casing program options, compatible drilling bit, and horizontal deviation);

III. The presence of geologic conditions that favor a particular fluid type or performance characteristic (

e.g.,

formation stability/sensitivity, formation pore pressure vs. fracture gradient, and potential for gas hydrate formation);

IV. Drilling fluid cost (

i.e.,

base cost plus daily operating cost);

V. drilling operation cost (

i.e.,

rig cost plus logistic and operation support); and

VI. Drilling waste disposal cost.

Industry has commented that while the right combination of factors that favor the use of SBF can occur in any area, they most frequently occur with “deep water” operations (

i.e.,

greater than or equal to 1,000 feet of water). This is due to the fact that these operations are higher cost and can therefore better justify the higher initial cost of SBF use. Industry has also commented that SBF may be increasingly used in shallow water wells due to the ability of SBF to increase average rates of penetration and shorten average times to complete drilling operations (Docket No. W-98-26, Record No. IV.A.a.3).

The volume of cuttings generated while drilling the SBF or OBF intervals of a well depends on the type of well (development or production) and the water depth (shallow or deep). EPA developed OBF and SBF model well characteristics from information provided by the American Petroleum Institute (API). API provided well size date for four types of wells currently drilling the GOM: development and exploratory wells in both deep water (

i.e.,

greater than or equal to 1,000 feet of water) and shallow water (

i.e.,

less than 1,000 feet of water). These model wells are referred to as: (1) Shallow-water development (SWD); (2) shallow-water exploratory (SWE); (3) deep-water development (DWD); and (4) deep-water exploratory (DWE). For the four model wells, EPA determined that the volumes of cuttings generated by these SBF or OBF well intervals are (in barrels): 565 for SWD; 1,184 for SWE; 855 for DWD; and 1,901 for DWE. These volumes represent only the rock, sand, and other formation solids drilled from the hole, and do not include drilling fluid that adheres to these formation cuttings. These values also include the additional formation cuttings volume of 7.5% washout. Washout is caving in or sloughing off of the well bore. Washout, therefore, increases hole volume and increases the amount of cuttings generated when drilling a well. The washout percentage EPA used in its analyses (

i.e.,

7.5%) is based on the rule of thumb reported by industry representatives of 5 to 10% washout when drilling with SBF or OBF.

Drilling fluid returning from the well is laden with drill cuttings. The drill cuttings range in size from large particles which are on the order of a centimeter or more in size to small particles (

i.e.,

fines or “low gravity solids”) which are fractions of a millimeter in size. Standard or current practice solids control systems employ primary and secondary shale shakers in series with a “fines removal unit” (

e.g.,

decanting centrifuge or mud cleaner). The drilling fluid and drill cuttings from the well are first passed through primary shale shakers. These shakers remove the largest cuttings which are approximately 1 to 5 millimeters in size. The drilling fluid recovered from the primary shakers is then passed over secondary shale shakers to remove smaller drill cuttings. Finally, a portion or all of the drilling fluid recovered from the primary and secondary shakers may be passed through the fines removal unit to remove fines from the drilling fluid. It is important to remove fines from the drilling fluid in order to maintain the desired rheological properties of the active drilling fluid system (

e.g.,

viscosity, density). Thus, the cuttings wastestream normally consists of discharged cuttings from the primary and secondary shale shakers and fines from the fines removal unit.

Operators using improved solids control technology process the cuttings discarded from the primary and secondary shale shakers through a “cuttings dryer” (

e.g.,

vertical or horizontal centrifuge, squeeze press mud recovery unit, High-G linear shaker). The cuttings from the cuttings dryer are discharged and the recovered SBF is sent to the fines removal unit. The advantage of the cuttings dryer is that more SBF is recovered for re-use and less SBF is discharged into the ocean. This, consequently, will reduce the pollutant loadings to the ocean and the potential of the waste to cause anoxia (lack of oxygen) in the receiving sediment.

As discussed in the April 2000 NODA (65 FR 21569), solids control equipment generally breaks larger particles into smaller particles. An undesirable increase in drilling fluid weight and viscosity can occur when drill solids degrade into fines and ultra-fines. Ultra-fines are generally classified as being less than 5 microns (10

-6

meters) in length and solids control equipment generally cannot remove these ultra-fines. An unacceptable high fines content (

i.e.,

generally > 5% of total drilling fluid weight) may consequently lead to drilling problems (

e.g.,

undesirable rheological properties, stuck pipe). Therefore, it is possible that the increased recovery of SBF from cuttings for re-use in the active mud system, often achieved through use of the cuttings dryer in solids control systems, may lead to a build-up in fines for certain formation characteristics (

e.g.,

high reactivity of formation cuttings, limited loss of drilling fluid into the formation). In the April 2000 NODA, EPA solicited comments regarding whether EPA's proposed numeric cuttings retention value might cause operators (where there are unfavorable formation characteristics) to: (1) Dilute the fines in the active mud system through the addition of “fresh” SBF; and/or (2) capture a portion of the fines in a container and send the fines to shore for disposal.

Comments from API/NOIA identified only one instance in which the use of a cuttings dryer in combination with a fines removal unit in the United States may have lead to an increase in “fines build-up” and a loss of circulation event (Docket No. W-98-26, Record No. IV.A.a.13). Further communication with additional industry stakeholders identified that this well (Shell, Green Canyon 69, OCS-G-13159#3) was the first application of the cuttings dryer type (horizontal centrifuge cuttings dryer) in the GOM and inexperience with this type of technology may have contributed to the build-up of fines causing well problems. However, other commentors stated that fines build-up was not an issue for the well in question (Docket No. W-98-26, Record No. IV.A.b.1). Moreover, further industry comments revealed that the properties of formations are often the main culprit of loss circulation and that the same rig (Marianas) had a loss of circulation at another nearby well in the same formation when a cuttings dryer was not being used (Docket No. W-98-26, Record No. IV.A.b.1). Therefore, based on the record, which includes over three dozen successful cuttings dryer deployments, EPA concludes that fines build up is not an issue of concern when operators properly operate and maintain cuttings dryers and fines removal equipment.

Drill cuttings are typically discharged continuously as they are separated from the drilling fluid in the solids separation equipment. The drill cuttings will also carry a residual amount of adhered drilling fluid. Therefore, the two parameters that make up the bulk of the pollutant loadings are TSS and what is measured by the API Retort Method (Appendix 7) as Total Oil. TSS is comprised of two components: the drill cuttings themselves and the solids in the adhered drilling fluid. The drill cuttings are primarily small bits of stone, clay, shale, and sand. The source of the solids in the drilling fluid is primarily the barite weighting agent, and clays (

e.g.,

amine clays) which are added for filtration control and to modify the rheological properties. Benthic smothering and/or sediment grain size alteration resulting in potential damage to invertebrate populations and alterations in benthic community structure is a concern with uncontrolled SBF drilling discharges due to the quantity and characteristics of associated TSS discharges. In general, large cuttings particles with a high percentage of adhering SBF (

e.g.,

>12% (wt. SBF)/(wt. wet cuttings)) tend to conglomerate and quickly settle out to the benthic environment quickly near the well site.

Additionally, environmental impacts can be caused by toxic, conventional, and non-conventional pollutants adhering to the solids. The adhered SBF drilling fluid is mainly composed, on a volumetric basis, of the synthetic material (

i.e.,

“base fluid”). Formation oil can also contaminate SBF-cuttings and contribute priority, conventional, and non-conventional pollutants. The oleaginous material (

i.e.,

SBF base fluid and formation oil) may be toxic and it may contain priority pollutants such as polynuclear aromatic hydrocarbons (PAHs). Depending on bottom currents, temperature, and rate of biodegradation this oleaginous material may cause hypoxia (

i.e.,

reduction in dissolved oxygen concentrations) or anoxia (

i.e.,

absence of dissolved oxygen) in the immediate sediment. Oleaginous materials which biodegrade quickly will reduce dissolved oxygen concentrations more rapidly than more slowly degrading oleaginous materials. EPA, however, thinks that fast biodegradation is environmentally preferable to slower biodegradation despite the increased risk of temporary hypoxia which accompanies fast biodegradation. EPA's position is supported by published seabed surveys which show that benthic re-colonization by infaunal individuals after the discharge of SBF-cuttings or OBF-cuttings can be correlated with the disappearance of the base fluid in the sediment. Large persistent cuttings piles may provide a source of environmental contamination for many years (Docket No. W-98-26, Record No. IV.F.2). Moreover, benthic re-colonization rates do not seem to be correlated with the severity of any hypoxic or anoxic effects that may result while the SBF base fluid is degrading or dispersing. Numerous studies show that SBF base fluids that biodegrade faster lead to a more rapid recovery of the pre-discharge benthic community.

As a component of the drilling fluid, the barite weighting agent is also discharged as a contaminant of the drill cuttings. Barite is a mineral principally composed of barium sulfate (BaSO

4

), and it is known to generally have trace contaminants of several toxic heavy metals such as mercury, cadmium, arsenic, chromium, copper, lead, nickel, and zinc. SBF also contain non-conventional pollutants found in other drilling fluid components (

e.g.,

emulsifiers, oil wetting agents, filtration control agents, and viscosifiers).

As previously stated in the April 2000 NODA (65 FR 21560), EPA learned that SBF is controlled with zero discharge practices at the drill floor, in the form of vacuums and sumps to retrieve spilled fluid. EPA also learned that approximately 75 barrels of fine solids and barite, which have an approximate SBF content of 25%, can accumulate in the dead spaces of the mud pit, sand trap, and other equipment in the drilling fluid circulation system. Current practice is to either wash these solids out with water for overboard discharge, or to retain the waste solids for disposal. Several hundred barrels (approximately 200 to 400 barrels) of water are used to wash out the mud pits. Industry representatives also indicated to EPA that those oil and gas extraction

operations that discharge wash water and accumulated solids first recover free SBF.

B. Selection of Pollutant Parameters

1. Stock Limitations and Standards for Base Fluids

a.

General.

In the final rule, where SBF-cuttings may be discharged, except for Cook Inlet, Alaska, EPA is establishing BAT limitations and NSPS that require the synthetic materials which form the base fluid of the SBFs to meet limitations and standards on PAH content, sediment toxicity, and biodegradation. If these stock limitations are not met the technology basis for meeting these limitations and standards is: (1) Product substitution; or (2) zero discharge based on land disposal or cuttings re-injection. The regulated toxic, conventional, and non-conventional pollutant parameters are identified below. A large range of synthetic, oleaginous, and water miscible materials are available for use as base fluids. These stock limitations on the base fluid are intended to encourage product substitution reflecting best available technology and best available demonstrated technology wherein only those synthetic materials and other base fluids which minimize potential loadings and toxicity may be discharged. Additionally, EPA is retaining BPT and BCT requirements for SBFs and SBF-cuttings as no discharge of free oil as determined by the static sheen text (Appendix 1 of subpart A of 40 CFR Part 435).

As stated below in Section V.F, EPA is today promulgating BPT, BCT, BAT, and NSPS for SBFs and SBF-cuttings for Coastal Cook Inlet, Alaska as zero discharge except when Coastal Cook Inlet, Alaska, operators are unable to dispose of their SBF-cuttings using any of the following disposal options: (1) On-site re-injection (annular disposal or Class II UIC); (2) re-injection using a nearby Coastal or Offshore Class II UIC disposal well; or (3) onshore disposal using a nearby Class II UIC disposal well or land application. If an operator is able to make these showings, then the operator would be subject to the same requirements for SBF-cuttings that apply elsewhere. The regulated toxic, conventional, and non-conventional pollutant parameters are identified below.

b.

PAH Content.

EPA is regulating the PAH content of base fluids because PAHs are comprised of toxic priority pollutants. SBF base fluids typically do not contain PAHs, whereas the traditional OBF base fluids of diesel and mineral oil typically contain 5 to 10% PAH and 0.35% PAH respectively. The PAHs typically found in diesel and mineral oil include: (1) the toxic priority pollutants fluorene, naphthalene, phenanthrene, and others; and (2) non-conventional pollutants such as alkylated benzenes and biphenyls. Therefore, the PAH BAT limitation and NSPS are components of this final regulation to help discriminate between acceptable and non-acceptable base fluids.

c.

Sediment Toxicity.

EPA is also regulating the sediment toxicity in base fluids as a non-conventional pollutant parameter and as an indicator for toxic pollutants and non-conventional pollutants in base fluids (

e.g.,

enhanced mineral oils, internal olefins, linear alpha olefins, poly alpha olefins, paraffinic oils, C

12

-C

14

vegetable esters of 2-hexanol and palm kernel oil, “low viscosity” C

8

esters, and other oleaginous materials). It has been shown, during EPA's development of the Offshore Guidelines, that establishing limits on toxicity encourages the use of less toxic drilling fluids and additives. Many of the SBF base fluids have been shown to have lower toxicity than OBF base fluids, but among SBFs some are more toxic than others. Today's final discharge option (

i.e.,

BAT/NSPS Option 2) includes a base fluid sediment toxicity stock limitation, as measured by the 10-day sediment toxicity test (ASTM E1367-92) using a natural sediment or formulated sediment and

Leptocheirus plumulosus

as the test organism.

d.

Biodegradation.

EPA is also regulating the biodegradation in base fluids as an indicator of the extent, in level and duration, of the toxic effect of toxic pollutants and non-conventional pollutants present in the base fluids (

e.g.,

enhanced mineral oils, internal olefins, linear alpha olefins, poly alpha olefins, paraffinic oils, C

12

-C

14

vegetable esters of 2-hexanol and palm kernel oil, “low viscosity” C

8

esters, and other oleaginous materials). Based on results from seabed surveys at sites where various base fluids have been discharged with drill cuttings, EPA believes that the results from the three biodegradation tests used during the rulemaking (

i.e.,

solid phase test, anaerobic closed bottle biodegradation test, respirometry biodegradation test) are indicative of the relative rates of biodegradation in the marine environment. In addition, EPA thinks the biodegradation parameter correlates strongly with the rate of recovery of the seabed where OBF- and SBF-cuttings have been discharged. The various base fluids vary widely in biodegradation rates, as measured by the three biodegradation methods. However, the relative ranking of the base fluids remain relatively similar across all three biodegradation tests.

As originally proposed in February 1999 (64 FR 5504) and re-stated in the April 2000 NODA (65 FR 21550), EPA is today promulgating a BAT limitation and NSPS to control the minimum amount of biodegradation of base fluid. Today's final discharge option (

i.e.,

BAT/NSPS Option 2) includes a base fluid biodegradation stock limitation, as measured by the marine anaerobic closed bottle biodegradation test (

i.e.,

ISO 11734).

e.

Bioaccumulation.

EPA also considered establishing a BAT limitation and NSPS that would limit the base fluid bioaccumulation potential. The regulated parameters would be the non-conventional and toxic priority pollutants that bioaccumulate. EPA reviewed the current literature to identify the bioaccumulation potential of various base fluids. EPA determined that SBFs are not expected to significantly bioaccumulate because of their extremely low water solubility and consequent low bioavailability. Their propensity to biodegrade makes them further unlikely to significantly bioaccumulate in marine organisms.

EPA identified that hydrophobic chemicals (

e.g.,

ester base fluids) that have a log K

ow

less than about 3 to 3.5 may bioaccumulate rapidly but not to high concentrations in tissues of marine organisms, particularly if they are readily biodegradable into non-toxic metabolites (Docket No. W-98-26, Record No. IV.F.1). (

Note:

The octanol/water partition coefficient (K

ow

) is used as a surrogate for estimating lipid/water partitioning). Moreover, hydrophobic chemicals (

e.g.,

C

16

-C

18

internal olefins, various poly alpha olefins, and C

18

n-paraffins) with a log K

ow

greater than about 6.5 to 7 do not bioaccumulate effectively from the water, because their solubility in both the water and lipid phases is very low (Docket No. W-98-26, Record No. IV.F.1). Finally, the degradation by-products of SBF base fluids (

e.g.,

alcohols) are likely to be more polar (

i.e.,

more miscible with water) than the parent substances. The higher water solubility will result in these degradation by-products partitioning into the water column and being diluted to toxicologically insignificant concentrations.

2. Discharge Limitations

a.

Free Oil.

Under BPT and BCT limitations for SBF-cuttings, EPA retains the prohibition on the discharge of free oil as determined by the static sheen test

(see

Appendix 1 of subpart A of 40 CFR part 435). Under this prohibition, drill cuttings may not be discharged when the associated drilling fluid would fail the static sheen test. The prohibition on the discharge of free oil is intended to minimize the formation of sheens on the surface of the receiving water. The regulated parameter of the no free oil limitation would be the conventional pollutant oil and grease which separates from the SBF and causes a sheen on the surface of the receiving water.

The free oil discharge prohibition does not control the discharge of oil and grease and crude oil contamination in SBFs as it would in WBFs. With WBFs, oils which may be present (

e.g.,

diesel oil, mineral oil, formation oil, or other oleaginous materials) are present as the discontinuous phase. As such these oils are free to rise to the surface of the receiving water where they may appear as a film or sheen upon or discoloration of the surface. By contrast, the oleaginous matrices of SBFs do not disperse in water. In addition they are weighted with barite, which causes them to sink as a mass without releasing either the oleaginous materials which comprise the SBF or any contaminant formation oil. Thus, the test would not identify these pollutants. However, a portion of the SBF may rise to the surface to cause a sheen. The components that rise to the surface fall under the general category of oil and grease and are considered conventional pollutants. Therefore, the purpose of the no free oil limitation of today's final regulation is to control the discharge of conventional pollutants which separate from the SBF and cause a sheen on the surface of the receiving water. The limitation is not intended to control formation oil contamination nor the total quantity of conventional pollutants discharged.

b.

Formation Oil Contamination.

As originally proposed in February 1999 (64 FR 5505) and re-stated in the April 2000 NODA (65 FR 21552), EPA is today promulgating a BAT limitation and NSPS of zero discharge to control formation oil contamination on SBF-cuttings. EPA is also today promulgating a screening method (Reverse Phase Extraction (RPE) method presented in Appendix 6 to subpart A of part 435) and a compliance assurance method (Gas Chromatograph/Mass Spectrometer (GC/MS) method presented in Appendix 5 to subpart A of part 435).

Formation oil is an “indicator” pollutant for the many toxic and priority pollutant pollutants present in formation (crude) oil (

e.g.,

aromatic and polynuclear aromatic hydrocarbons). These pollutants include benzene, toluene, ethylbenzene, naphthalene, phenanthrene, and phenol. EPA is requiring that formation oil contamination be measured at two points. First, EPA is requiring that operators verify and document that a SBF is free of formation oil contamination before initial use of the SBF through use of the GC/MS compliance assurance method (Appendix 5 to subpart A of 40 CFR part 435). Second, EPA is requiring that operators use the RPE method (Appendix 6 to subpart A of 40 CFR part 435) for the SBF recovered by the solids control equipment to detect formation oil contamination. The RPE method is a fluorescence test and is appropriately “weighted” to better detect crude oils. These crude oils contain more toxic aromatic and PAH pollutants and show brighter fluorescence (

i.e.,

noncompliance) in the RPE method at lower levels of crude oil contamination. Since the RPE method is a relative brightness test, operators may also use the GC/MS compliance assurance method when the results from the RPE method are in doubt by either the operator or the enforcement authority. Results from the GC/MS compliance assurance method will supersede those of the RPE method.

c.

Retention of Drilling Fluid on Cuttings.

EPA is today promulgating a BAT limitation and NSPS to control the retention of drilling fluid on drill cuttings. The BAT limitation and NSPS are presented as the percentage of base fluid on wet cuttings (

i.e.,

mass base fluid (g)/mass wet cuttings (g)), averaged over the entire well sections drilled with SBF. The limitation and standard controls the quantity of drilling fluid discharged with the drill cuttings. Both toxic pollutants and non-conventional pollutants would be controlled by this limitation. Several pollutants are present in the barite weighting agent, including the toxic metal pollutants arsenic, chromium, copper, lead, mercury, nickel, and zinc, and the non-conventional metal pollutants aluminum and tin. A complete SBF formulation also includes non-conventional pollutants found in the SBF base fluids (

e.g.,

enhanced mineral oils, internal olefins, linear alpha olefins, poly alpha olefins, paraffinic oils, C

12

-C

14

vegetable esters of 2-hexanol and palm kernel oil, “low viscosity” C

8

esters, and other oleaginous materials) and in other drilling fluid components (

e.g.,

emulsifiers, oil wetting agents, filtration control agents, and viscosifiers). These pollutants would not be controlled by the sediment toxicity stock limitations. In response to the February 1999 proposal (64 FR 5501), EPA received comments that these non-conventional pollutants include fatty acids (Docket No. W-98-26, Record No. III.A.a.7). EPA also received further information that the non-conventional pollutants in these drilling fluid components include amine clays, amine lignites, and dimer/trimer fatty acids (Docket No. W-98-26, Record No. III.B.b.1).

This limitation would also control the toxic effect of the drilling fluid and the persistence or biodegradation of the base fluid. Specifically, as stated in the April 2000 NODA (65 FR 21553), lowering the percentage of residual drilling fluid retained on cuttings increases the recovery rate of the seabed receiving the cuttings (Docket No. W-98-26, Record No. I.D.b.30 and 31; Record No. III.B.a.15). Limiting the amount of SBF content in discharged cuttings controls: (1) The amount of toxic and non-conventional pollutants in SBF which are discharged to the ocean; (2) the biodegradation rate of discharged SBF; and (3) the potential for SBF-cuttings to develop cuttings piles and mats which are deleterious to the benthic environment.

As originally proposed in February 1999 (64 FR 5547) and re-stated in the April 2000 NODA (65 FR 21552), EPA is today promulgating a retort and sampling compliance method for the cuttings retention BAT limitation and NSPS (

see

Appendix 7 to subpart A of 40 CFR part 435; API Recommended Practice 13B-2).

d.

Sediment Toxicity.

EPA is also regulating the sediment toxicity in SBF discharged with cuttings as a non-conventional pollutant parameter and as an indicator for toxic pollutants in SBFs. As originally proposed in February 1999 (64 FR 5491) and re-stated in April 2000 (65 FR 21557), EPA is today promulgating a BAT limitation and NSPS to control the maximum sediment toxicity of the SBF discharged with cuttings at the point of discharge. The sediment toxicity of the SBF-cuttings at the point of discharge is measured by the modified sediment toxicity test (ASTM E1367-92) using a natural sediment or formulated sediment and

Leptocheirus plumulosus

as the test organism.

EPA finds that the sediment toxicity test at the point of discharge is practical as an indicator of the sediment toxicity of the drilling fluid at the point of discharge. The sediment toxicity test applied at the point of discharge will control non-conventional pollutants found in some drilling fluid components (

e.g.,

emulsifiers, oil wetting agents, filtration control agents,

and viscosifiers) which are added to the base fluid in order to build a complete SBF package. Other possible toxic pollutants in drilling fluids may include mercury, cadmium, arsenic, chromium, copper, lead, nickel, and zinc, and formation oil contaminants. As previously stated, establishing discharge limits on toxicity encourages the use of less toxic drilling fluids and additives. The modifications to the 10-day sediment toxicity test include shortening the test to 96-hours. Shortening the test will allow operators to continue drilling operations while the sediment toxicity test is being conducted on the discharged drilling fluid. Moreover, discriminatory power is substantially reduced for the 10-day test on drilling fluid as compared to the 96-hour test (

i.e.,

the 10-day test is of lower practical use in determining whether a SBF is substantially different from OBFs). Finally, operators discharging WBFs are already complying with a biological test at the point of discharge, the 96-hour SPP toxicity test, which tests whole WBF aquatic toxicity using the test organism

Mysidopsis bahia

.

3. Maintenance of Current Requirements

Today's rule does not modify the existing BAT and NSPS limitations on the stock barite of 1 mg/kg mercury and 3 mg/kg cadmium. These limitations control the levels of toxic pollutant metals because cleaner barite that meets the mercury and cadmium limits is also likely to have reduced concentrations of other metals. Evaluation of the relationship between cadmium and mercury and the trace metals in barite shows a correlation between the concentration of mercury with the concentration of arsenic, chromium, copper, lead, molybdenum, sodium, tin, titanium and zinc (

see

Section VI, Offshore Development Document, EPA-821-R-93-003).

Today's rule does not modify the existing BAT and NSPS limitations prohibiting the discharge of drilling wastes containing diesel oil in any amount. Diesel oil is considered an “indicator” for the control of specific toxic pollutants. These pollutants include benzene, toluene, ethylbenzene, naphthalene, phenanthrene, and phenol. Diesel oil may contain from 3 to 10% by volume PAHs, which constitute the more toxic pollutants in petroleum products.

Today's rule does not modify the existing BAT limitation and NSPS for controlling the maximum aqueous phase toxicity of SBF-cuttings at point of discharge using the suspended particulate phase (SPP) test (

see

Appendix 2 of subpart A of Part 435). The BAT limitation and NSPS for controlling aqueous toxicity of discharged SBF-cuttings is retained as the minimum 96-hour LC

50

of the SPP shall be 3% by volume. EPA is interested in controlling the toxicity of drilling fluids in the sediment and the water column and is requiring both a sediment toxicity test and an aqueous phase toxicity test to assess overall toxicity of the drilling fluid at the point of discharge. EPA finds that the SPP test at the point of discharge is practical as a measurement of the aquatic toxicity of the drilling fluid at the point of discharge. The discharge SPP test will control non-conventional pollutants found in drilling fluid components (

e.g.,

emulsifiers, oil wetting agents, filtration control agents, and viscosifiers) which are added to the base fluid in order to build a complete SBF package. Moreover, operators discharging WBFs are already complying with the SPP toxicity test on discharged WBFs.

C. Regulatory Options Considered and Selected for Drilling Fluid Not Associated With Drill Cuttings

In the February 1999 proposal, EPA proposed BPT, BCT, BAT, and NSPS as zero discharge for SBFs not associated with drill cuttings. In the April 2000 NODA, EPA published two options for the final rule for the BAT limitation and NSPS for controlling SBFs not associated with SBF drill cuttings: (1) Zero discharge; or (2) allowing operators to choose either zero discharge or an alternative set of BMPs with an accompanying compliance method. Industry supported the second option stating that the first option (zero discharge) would result in the costly and potentially dangerous collection, shipping, and disposal of large quantities of rig site wash water containing only a small quantity of SBF (Docket No. W-98-26, Record No. IV.A.a.13). Industry also stated that BMPs would be extremely effective at reducing the quantity of non-cuttings related SBF and would focus operators' attention on reducing these discharges.

EPA is today promulgating BPT, BCT, BAT, and NSPS of zero discharge for SBFs not associated with drill cuttings. This wastestream consists of neat SBFs that are intended for use in the downhole drilling operations (

e.g.,

drill bit lubrication and cooling, hole stability). This wastestream is transferred from supply boats to the drilling rig and can be released during these transfer operations. This wastestream is often spilled on the drill deck but contained through grated troughs, vacuums, or squeegee systems. This wastestream is also held in numerous tanks during all phases of the drilling operation (

e.g.,

trip tanks, storage tanks). EPA received information that rare occurrences of improper SBF transfer procedures (

e.g.,

no bunkering procedures in place for rig loading manifolds) and improper operation of active mud system equipment (

e.g.,

no lock-out, tag-out procedures in place for mud pit dump valves) has the potential for the discharge of tens to hundreds of barrels of neat SBF, or SBF not associated with cuttings, if containment is not practiced (Docket No. W-98-26, Record No. IV.A.a.26, QTECH LTD Reports for Ocean America and Discoverer 534).

Current practice for control of SBF not associated with drill cuttings is zero discharge (

e.g.,

drill deck containment, bunkering procedures), primarily due to the value of SBFs recovered and reused. Therefore, zero discharge for SBF not associated with drill cuttings is technologically available and economically achievable. Moreover, these controls generally allow the re-use of SBF in the drilling operation and has no unacceptable NWQIs.

EPA has also decided that solids accumulated at the end of the well (“accumulated solids”) and wash water used to clean out accumulated solids or on the drill floor are associated with drill cuttings and are therefore not controlled by the zero discharge requirement for SBFs not associated with drill cuttings (

see

Section V.F.2.b).

D. BPT Technology Options Considered and Selected for Drilling Fluid Associated With Drill Cuttings

EPA is today promulgating BPT effluent limitations for the cuttings contaminated with SBFs (“SBF-cuttings”). The BPT effluent limitations promulgated today for SBF-cuttings would control free oil as a conventional pollutant. The BPT limitation is no free oil as measured by the static sheen test, performed on SBF separated from the cuttings in U.S. Offshore waters and Coastal Cook Inlet, Alaska.

In setting the no free oil limitation in U.S. Offshore waters and Coastal Cook Inlet, Alaska, EPA considered the sheen characteristics of currently available SBFs. Since this requirement is currently met by dischargers in the GOM, EPA anticipates no additional costs to the industry to comply with this limitation. Therefore, EPA believes that this limitation represents the appropriate level of control for SBFs associated with drill cuttings.

E. BCT Technology Options Considered and Selected for Drilling Fluid Associated With Drill Cuttings

In July 1986, EPA promulgated a methodology for establishing BCT effluent limitations. EPA evaluates the reasonableness of BCT candidate technologies—those that are technologically feasible—by applying a two part cost test: (1) A POTW test; and (2) an industry cost-effectiveness test.

EPA first calculates the cost per pound of conventional pollutant removed by industrial dischargers in upgrading from BPT to a BCT candidate technology and then compares this cost to the cost per pound of conventional pollutants removed in upgrading POTWs from secondary treatment. The upgrade cost to industry must be less than the POTW benchmark of $0.25 per pound (in 1976 dollars). In the industry cost-effectiveness test, the ratio of the incremental BPT to BCT cost divided by the BPT cost for the industry must be less than 1.29 (i.e., the cost increase must be less than 29%).

The BCT effluent limitations promulgated today would control free oil as a conventional pollutant. EPA is today promulgating a BCT effluent limitation for SBF-cuttings of no free oil equivalent to the BPT limitation for SBF-cuttings of no free oil as determined by the static sheen test in U.S. Offshore waters and Coastal Cook Inlet, Alaska.

In developing BCT limits for the U.S. Offshore waters and Coastal Cook Inlet, Alaska, EPA considered whether there are technologies (including drilling fluid formulations) that achieve greater removals of conventional pollutants than promulgated for BPT, and whether those technologies are cost-reasonable according to the BCT Cost Test. EPA identified no technologies that can achieve greater removals of conventional pollutants as compared with the U.S. Offshore waters and Coastal Cook Inlet BPT requirements that are also cost-reasonable under the BCT Cost Test. Accordingly EPA is today promulgating BCT effluent limitations for SBF-cuttings equal to the promulgated BPT effluent limitations for SBF-cuttings in U.S. Offshore waters and Coastal Cook Inlet, Alaska.

F. BAT Technology Options Considered and Selected for Drilling Fluid Associated With Drill Cuttings

EPA is promulgating stock limitations and discharge limitations in a two part approach to control SBF-cuttings discharges under BAT. The first part is based on product substitution through use of stock limitations (

e.g.,

sediment toxicity, biodegradation, PAH content, metals content) and discharge limitations (

e.g.,

diesel oil prohibition, formation oil prohibition, sediment toxicity, aqueous toxicity). The second part is the control of the quantity of SBF discharged with SBF-cuttings. As previously stated in the April 2000 NODA, EPA finds that the second part is particularly important because limiting the amount of SBF content in discharged cuttings controls: (1) The amount of SBF discharged to the ocean; (2) the biodegradation rate of discharged SBF; and (3) the potential for SBF-cuttings to develop cuttings piles and mats which are detrimental to the benthic environment.

EPA is also today retaining the existing BAT limitations on: (1) The stock barite of 1 mg/kg mercury and 3 mg/kg cadmium; (2) the maximum aqueous toxicity of discharged SBF-cuttings as the minimum 96-hour LC

50

of the Suspended Particulate Phase toxicity test (SPP) shall be 3% by volume; and (3) prohibiting the discharge of drilling wastes containing diesel oil in any amount. These limitations control the levels of toxic metal and aromatic pollutants respectively. EPA at this time thinks that all of these components are essential for appropriate control of SBF-cuttings discharges.

The BAT effluent limitations promulgated today for SBF-cuttings would control a variety of toxic and non-conventional pollutants in the stock base fluids by controlling their PAH content, sediment toxicity, and biodegradation. The BAT effluent limitations promulgated today for SBF-cuttings would also control a variety of toxic and non-conventional pollutants at the point of discharge by controlling formation oil contamination, sediment toxicity, and the quantity of SBF discharged. The BAT stock and discharge limitations are described below.

The BAT level of control in the U.S. Offshore waters has been developed taking into consideration among other things: (1) The availability, cost, and environmental performance of SBF base fluids in terms of PAH content, sediment toxicity, and biodegradation rate; (2) the availability, cost, and environmental performance of SBFs retained on the cuttings discharge in terms of sediment toxicity and biodegradation rate; (3) the frequency of formation oil contamination at the various control levels for the discharges; (4) the availability, cost, and environmental performance of equipment and methods to recover SBF from the drill cuttings being discharged; and (5) the NWQIs of each option. By environmental performance, EPA means both a reduction in the quantity of pollutants discharged to the ocean and a reduction in their environmental effects in terms of sediment toxicity, aquatic toxicity, and biodegradation rate. Issues related to the technical availability and economic achievability of today's promulgated BAT limitations are discussed below by regulated parameter. The NWQIs of each selected option is discussed in Section VIII below. EPA also considered NWQIs in selecting the controlled discharge option for SBF-cuttings (

i.e.,

BAT/NSPS Option 2) (

see

Section VIII).

EPA and industry sediment toxicity and biodegradation laboratory studies show that both vegetable esters and low viscosity esters have better environmental performance than all other SBF base fluids. EPA, however, rejected the option of basing BAT sediment toxicity and biodegradation stock limitations and NSPS solely on vegetable esters and low viscosity esters because the record does not indicate that these fluids can be used in drilling situations throughout the offshore subcategory nor could EPA predict the conditions and circumstances where these fluids would be able to be used (

see

Section V.F.1.a). EPA is sufficiently satisfied, however, that both esters provide better environmental performance (

e.g.,

sediment toxicity, biodegradation). Consequently, EPA is promulgating an alternative higher retention on cuttings (ROC) BAT discharge limitation to encourage the use of esters. The higher ROC discharge limitation for SBFs complying with the stock limitations based on esters is derived from data representing four cuttings dryer technologies (

e.g.,

vertical centrifuge, horizontal centrifuge, squeeze press mud recovery unit, and High-G linear shaker). The lower ROC BAT discharge limitation for the SBFs complying with the C

16

-C

18

internal olefin stock limitations is based on data from the two top performing cuttings dryer technologies (

e.g.,

vertical centrifuge and horizontal centrifuge). EPA data demonstrates that operators properly using these cuttings dryer technologies (

e.g.,

vertical centrifuge, horizontal centrifuge, squeeze press, High-G linear shaker) will be able to comply with the final higher ROC numerical limitation for ester-based SBFs. EPA believes that this balancing of the importance of retention values with environmental performance as reflected by sediment toxicity and biodegradation rates is justified because of the greater ability of esters to

biodegrade and of their lower sediment toxicity.

Therefore, EPA balanced the environmental performance of the base fluid (in terms of sediment toxicity and biodegradation) with the environmental performance of cuttings associated with drilling fluids (in terms of the retention on cuttings limit) to determine the appropriate best available technology. EPA determined that the improved toxicity and biodegradation of the ester based fluids justified increased flexibility in the ROC limitation as long as the limitation reflected the use of cuttings dryers technologies.

EPA, however, did not base the higher ROC BAT discharge limitation for esters on current shale shaker technology because this does not represent the best available technology (or best available demonstrated technology). EPA does not believe that the improved environmental performance of esters justifies the huge difference in pollutant loadings between existing shale shaker technology and newer cuttings dryer technology. Because the effluent limitations and standards promulgated in this rule account for variability, the effluent limitation and standards are higher than the long term average upon which the technology is based. Here, the LTA for the esters ROC limitation of 9.4% is 4.8%; while the LTA for the IOs ROC limitation of 6.9% is 3.82%. By contrast, the LTA for existing shale shaker technology is 10.2%. This difference translates to 118 million pounds per year of pollutants being discharged using the existing and new model well counts for the selected BAT option (

i.e.,

BAT/NSPS Option 2) (

see

SBF Development Document). Further, as previously stated in the April 2000 NODA (65 FR 21553), field results show that: (1) Cuttings are dispersed during transit to the seabed and no cuttings piles are formed when SBF concentrations on cuttings are held below 5%; and (2) cuttings discharged from cuttings dryers (with SBF retention values under 5%) in combination with a sea water flush, hydrate very quickly and disperse like water-based cuttings. Thus, while EPA is willing to provide additional flexibility to dischargers of ester-based fluids, EPA believes that the appropriate technology basis that reflects BAT is cuttings dryers technology.

EPA determined that zero discharge for BAT was technically feasible and economically achievable because prior to the use of SBFs, the industry was able to operate using only the traditional OBFs (based on diesel oil and mineral oil), which are prohibited from discharge. EPA concluded that a zero discharge BAT limitation for SBF-cuttings would decrease the use of SBFs in favor of OBFs and WBFs. This is because a zero discharge BAT limitation for SBF-cuttings would create an incentive for operators to use the least expensive drilling fluids (

i.e.,

OBFs, WBFs) in order to minimize overall compliance costs.

EPA rejected the BAT zero discharge option for SBF-cuttings wastes because it would result in unacceptable increases in NWQIs. Therefore, EPA rejected the zero discharge option for SBF-cuttings wastes in U.S. waters in the Offshore subcategory of 40 CFR part 435 (“U.S. Offshore waters”). As previously stated in Section II.B, use of OBFs in place of SBFs would lead to an increase in NWQIs including the toxicity of the drilling waste. Use of WBFs in place of SBFs would generally lead to a per well increase in pollutants discharged, an increase in NWQIs, and an increase in aquatic toxicity. WBF drilling operations lead to per well increases in pollutants discharged because WBFs generate six times more washout (

e.g.,

sloughing) of the well wall than SBFs. Also, WBF drilling operations lead to increases in NWQIs because WBF drilling operations generally take longer than SBF drilling operations which lead to more air emissions and fuel usage from drilling rigs and equipment. Aquatic toxicity generally increases when drilling fluid manufacturers add supplements (

e.g.,

glycols, shale inhibitors) to WBFs for the purpose of making WBFs have technical capabilities (

e.g.,

lubricity, shale suppression) similar to SBFs. EPA estimates that, under the zero discharge option, some operators would switch to WBF compositions with more non aqueous drilling fluid properties (

e.g.,

lubricity, shale suppression), and that these WBFs would exhibit greater aquatic toxicity.

EPA's analyses show that under the SBF-cuttings zero discharge option as compared to current practice, for U.S. Offshore waters existing sources, there would be an increase of 35 million pounds of cuttings annually shipped to shore for disposal in non-hazardous oilfield waste (NOW) sites and an increase of 166 million pounds of cuttings annually injected. In addition, under the SBF-cuttings zero discharge option, operators would use the more toxic OBFs. The zero discharge option for SBF-cuttings would lead to an increase in annual fuel usage of 358,664 BOE and an increase in annual air emissions of 5,602 tons. Finally, the SBF-cuttings zero discharge option in the U.S. Offshore waters would lead to an increase of 51 million pounds of WBF cuttings being discharged to U.S. Offshore waters. This pollutant loading increase is a result of GOM operators switching from efficient SBF drilling to less efficient WBF drilling.

EPA's analysis shows that the impacts of adequately controlled SBF discharges to the water column and benthic environment are of limited scope and duration. By contrast, the landfilling of OBF-cuttings is of a longer term duration and associated pollutants may affect ambient air, soil, and groundwater quality. EPA and DOE documented at least five CERCLA (or “Superfund”) sites in Louisiana and California contaminated with oilfield wastes and more than a dozen other sites subject to Federal or State cleanup actions.

Nonetheless, while SBF-cuttings discharge with adequate controls is preferred over zero discharge in U.S. Offshore waters, SBF-cuttings discharge with inadequate controls is not preferred over zero discharge. EPA believes that to allow discharge of SBF-cuttings in U.S. Offshore waters, there must be appropriate controls to ensure that EPA's discharge limitations reflect the “best available technology” or other appropriate level of technology. EPA has worked with industry to address the appropriate determination of PAH content, sediment toxicity, biodegradation, quantity of SBF discharged, and formation oil contamination that are technically available, economically achievable, and have acceptable NWQIs. The final BAT limitations are a result of this effort and are discussed below.

EPA is today promulgating BAT of zero discharge for SBF-cuttings for Coastal Cook Inlet, Alaska except when Coastal Cook Inlet, Alaska, operators are unable to dispose of their SBF-cuttings using any of the following disposal options: (1) On-site re-injection (annular disposal or Class II UIC); (2) re-injection using a nearby Coastal or Offshore Class II UIC disposal well; or (3) onshore disposal using a nearby Class II UIC disposal well or land application. Coastal Cook Inlet, Alaska, operators are required to demonstrate to the NPDES permit controlling authority that none of the above three disposal options are technically feasible in order to qualify for the alternate BAT limitation. Coastal Cook Inlet, Alaska, operators that qualify for the alternate BAT limitation are allowed to discharge SBF-cuttings at the same level of BAT control as operators in Offshore waters. The NPDES permit controlling authority will use the procedure given in Appendix 1 to subpart D of 40 CFR part 435 to establish whether or not a Coastal Cook Inlet, Alaska, operator qualifies for the

SBF-cuttings zero discharge exemption. As stated in Appendix 1 to subpart D of 40 CFR part 435, the following factors are considered in the determination of whether or not Coastal Cook Inlet, Alaska, operators qualify for the SBF-cuttings zero discharge exemption: (1) Inability to establish formation injection in wells that were initially considered for annular or dedicated disposal; (2) inability to prove to UIC controlling authority that the waste will be confined to the formation disposal interval; (3) inability to transport drilling waste to an offshore Class II UIC disposal well or an onshore disposal site; and (4) whether or not there is no available land disposal facilities (

e.g.,

onshore re-injection, land disposal).

EPA finds that this option is technically available and economically achievable. Operators are currently barred from discharging OBFs, SBFs, and enhanced mineral oil based drilling fluids under the Cook Inlet NPDES general permit (64 FR 11889). As previously discussed in Section IV.E, EPA identified that many Cook Inlet operators in Coastal waters are using cuttings re-injection to comply with zero discharge disposal requirements for OBFs and OBF-cuttings. EPA contacted Cook Inlet operators (

e.g.,

Phillips, Unocal, Marathon Oil) and the State regulatory agency, AOGCC, for more information on the most recent re-injection practices of Coastal and Offshore Cook Inlet operators. AOGCC stated that there should be enough formation re-injection disposal capacity for the small number of non-aqueous drilling fluid wells (<5-10 wells per year) being drilled in Cook Inlet Coastal waters. Therefore, since Coastal Cook Inlet operators are already complying with zero discharge of OBF- and SBF-cuttings, this option is economically achievable as there are no incremental compliance costs.

AOGCC stated, however, that case specific limitations should be considered when evaluating disposal options (

see

Section IV.E). Cook Inlet, Alaska, operators may experience the following difficulties in attempting to comply with a zero discharge requirement for SBFs: (1) Inability to establish formation injection in wells that were initially considered for annular or dedicated Class II UIC disposal; (2) inability to prove to AOGCC's satisfaction that the waste will be confined to the formation disposal interval; and (3) inability to transport drilling waste to an offshore Class II UIC disposal well or an onshore disposal site. EPA believes that while these problems are currently not presented by drilling in Cook Inlet, they could be a problem in the future. Further, EPA believes this to be a greater problem in Cook Inlet where climate, tides, and its distance from commercial disposal sites make transportation to shore less feasible than in other offshore waters near the continental U.S. If EPA did not provide for some exceptions within the guideline itself, and these problems presented themselves beyond the time frame for requesting a Fundamentally Different Factors variance (under section 301(n)(2) of the CWA, 180 days) this would render zero discharge not achievable. Therefore, EPA believes it is reasonable to provide for some flexibility to the current practice of zero discharge in Cook Inlet.

EPA further finds the NWQIs of this option for Cook Inlet to be acceptable. As previously stated, few non-aqueous drilling fluid wells are drilled in Coastal Cook Inlet, Alaska (<5-10 wells per year). EPA finds that the small number of wells drilled per year (even if all of them are drilled using SBF) leads to very small increases in NWQIs. Tables 6 though 10 describe the annual air emissions and fuel usage for the three geographic regions including Cook Inlet, Alaska. In particular, a zero discharge requirement for SBFs and SBF-cuttings in Cook Inlet, Alaska, would lead to an annual increase of 94 tons of air emissions and 6,067 BOE fuel used for existing sources. EPA does not anticipate and new sources in Cook Inlet, Alaska. Consequently, EPA finds that the overall small increases in NWQIs from the zero discharge option, as compared to either of the two SBF-cuttings discharge options, in Coastal Cook Inlet, Alaska, are acceptable. The two SBF-cuttings discharge options show little change in NWQIs as compared to baseline (

see

Tables 6 though 9).

1. Stock Base Fluid Technical Availability and Economic Achievability

a. Introduction. As SBFs have developed over the past few years, the industry has come to use mainly a limited number of primary base fluids. These include the internal olefins, linear alpha olefins, poly alpha olefins, paraffinic oils, C

12

-C

14

vegetable esters of 2-hexanol and palm kernel oil, and “low viscosity” C

8

esters. These fluids represent virtually all the SBFs currently used in oil and gas extraction industry. EPA collected data on performance, environmental impact, and costs for these SBFs to develop the effluent limitations for today's final rule. The following definitions are used in this preamble to describe various SBFs: (1) Internal olefin (IO) refers to a series of isomeric forms of C

16

and C

18

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

14

and C

16

monoenes; (3) poly alpha olefin (PAO) refers to a mix mainly comprised of a hydrogenated decene dimer C

20

H

62

(95%), with lesser amounts of C

30

H

62

(4.8%) and C

10

H

22

(0.2%); (4) vegetable ester refers to a monoester of 2-ethylhexanol and saturated fatty acids with chain lengths in the range C

8

-C

16

; and (5) “low viscosity” ester refers to an ester of natural or synthetic C

8

fatty acids and alcohols. EPA also has data on other SBF base fluids, such as enhanced mineral oil, paraffinic oils (

i.e.,

saturated hydrocarbons or “alkanes”), and the traditional OBF base fluids: mineral oil and diesel oil.

The stock base fluid limitations in today's rule are based on the technology of product substitution. The promulgated limitations are technically available because they are based on currently available base fluids that can be used in the wide variety of drilling situations in U.S. offshore waters. EPA anticipates that the base fluids meeting all requirements would include vegetable esters, low viscosity esters, and internal olefins. In addition, based on current information, EPA believes that the stock base fluid controls on PAH content, sediment toxicity, and biodegradation rate being promulgated today are sufficient to only allow the discharge of only those base fluids (

e.g.,

esters, internal olefins) with lower bioaccumulation potentials (

i.e.,

log K

ow

<3 to 3.5 and log K

ow

> 6.5 to 7). Therefore, EPA found it was unnecessary to promulgate a separate limitation for bioaccumulation.

As previously stated in April 2000 (65 FR 21554), EPA considered basing the sediment toxicity and biodegradation stock limitations and standards solely on vegetable esters (

i.e.,

original esters) instead of the proposed C

16

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IO. EPA also considered subcategorizing the final rule to determine when vegetable esters are not practical and when C

16

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18

IOs could be used instead. EPA considered these options due to the potential for better environmental performance of vegetable ester-based drilling fluids. EPA and industry analytical testing show that esters have better sediment toxicity and biodegradation performance.

EPA rejected the option of basing sediment toxicity and biodegradation stock limitations and standards on vegetable esters due to several technical limitations. These technical limitations of vegetable esters preclude their use in all areas of the GOM, Offshore California, and Cook Inlet, Alaska. Vegetable ester technical limitations

include: (1) High viscosity compared with other IO SBFs at all temperatures, with an increasing difference as temperature decreases, leading to lower rates of penetration in wells and greater probability of losses due to higher equivalent circulating densities; (2) high gel strength in risers that develops when a vegetable ester-based SBF is not circulated; (3) a high temperature stability limit ranging from about 225 °F to perhaps 320 °F—the exact value depends on the detailed chemistry of the vegetable ester (

i.e.,

the acid, the alcohol) and the drilling fluid chemistry; (4) reduction of the thermal stability limit through hydrolysis when vegetable esters are in contact with highly basic materials (

e.g.,

lime, green cement) at elevated temperatures; and (5) less tolerance of the muds to contamination by seawater, cement, and drill solids than is observed for IO-SBFs (Docket No. W-98-26: Record No. IV.A.a.3, Attachment A2—“Limitations of Esters'; Record No. IV.A.a.13, Attachments Ester-51, 52, 53, 54, 56).

EPA also rejected the option of subcategorizing the use of esters to define drilling conditions when only esters could be allowed for a controlled discharge. EPA could not establish a “bright line” rationale to define the situation where only esters should be the benchmark fluid (

i.e.,

only esters would be allowed for a controlled discharge). EPA considered many of the engineering factors used for selection of a drilling fluid (

e.g.,

rig size and equipment; formation characteristics; water depth and environment; lubricity, rheological, and thixotropic requirements) and determined that this type of sub-categorization was not possible. EPA, however, is encouraging the use of esters by promulgating a higher ROC limitation and standard when esters are used.

EPA also considered basing sediment toxicity and biodegradation stock limitations and standards on low viscosity esters. Comments to the April 2000 NODA state that laboratory analyses, which were designed to simulate GOM conditions to which a fluid may be exposed, indicate that low viscosity esters have the following technical properties: (1) Similar or better viscosity than C

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IOs; (2) can be used to formulate stable low viscosity ester-based SBFs up to 300 °F; (3) can be used to formulate low viscosity ester-based SBFs to 16.0+ lbs/gal mud weight; (4) can reduce oil/water ratios to 70/30, thus reducing volumes of base fluid discharged; (5) high tolerance to drilled solids; (6) flat gels make it easier to break circulation, minimizing initial circulation pressures and subsequent risk of fracture; (7) high tolerance to seawater contamination; and (8) rheological properties can be adjusted by use of additives to suit specific conditions (Docket No. W-98-26, Record No. IV.A.a.7). EPA also received information on one well section drilled with low viscosity esters. Some of the results from this low viscosity ester well section were compared to the results from another well section in the same location where C

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IOs were used. These results show that the low viscosity ester had: (1) Comparable or better equivalent circulating densities (

i.e.,

acceptable fluid properties); and (2) faster ROP through better hole cleaning and higher lubricity (

i.e.,

fewer days required to drill to total depth which lead to less NWQI and overall drilling costs). The low viscosity esters are relatively new base fluids and have only recently been available to the market. Despite the results from the laboratory analyses and one well section, EPA does not believe that this is enough information to make the determination that low viscosity esters can be used in all or nearly all drilling conditions in the offshore U.S. waters (

e.g.,

differing formations, water depths, and temperatures). Therefore, EPA rejected the option of basing sediment toxicity and biodegradation stock limitations and standards on low viscosity esters. EPA is sufficiently satisfied, however, that low viscosity esters and vegetable esters provide better environmental performance (

e.g.,

sediment toxicity, biodegradation). Consequently, EPA is promulgating higher retention on cuttings discharge limitations where esters are used to encourage operators to use esters when possible.

b. PAH Content Technical Availability. Today's promulgated limitation of PAH content for U.S. Offshore waters is a weight ratio defined as the weight of PAH (as phenanthrene) per weight of the stock base fluid sample. The PAH weight ratio is 0.001%, or 10 parts per million (ppm). This limitation is based on the availability of base fluids that are free of PAHs and the detection of the PAHs by EPA Method 1654A, “PAH Content of Oil by High Performance Liquid Chromatography with a UV Detector.” Method 1654A was published in Methods for the Determination of Diesel, Mineral and Crude Oils in Offshore Oil and Gas Industry Discharges (EPA-821-R-92-008, incorporated by reference and available from National Technical Information Service at (703) 605-6000). As originally proposed in February 1999 (64 FR 5503), EPA is promulgating the use of the EPA Method 1654A for compliance with this PAH content BAT limitation.

EPA's promulgated PAH content limitation is technically available. Producers of several SBF base fluids have reported to EPA that their base fluids are free of PAHs. The base fluids which suppliers have reported are free of PAHs include IOs, LAOs, vegetable esters, low viscosity esters, certain enhanced mineral oils, synthetic paraffins, certain non-synthetic paraffins, and others. The use of these fluids can accommodate the broad varieties of drilling situations faced by industry in offshore U.S. waters (

see

SBF Development Document, Chapter IV). Compliance with the stock BAT limitation and NSPS on PAH content will be achieved by product substitution.

c. Sediment Toxicity Technical Availability. EPA is today promulgating a sediment toxicity stock base fluid limitation that would only allow the discharge of SBF-cuttings using SBF base fluids as toxic or less toxic, but not more toxic, than C

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IOs. Alternatively, this limitation could be expressed in terms of a “sediment toxicity ratio” which is defined as 10-day LC

50

of C

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18

internal olefins divided by the 10-day LC

50

of stock base fluid being tested. EPA is promulgating a sediment toxicity ratio of less than 1.0. Compliance with this limitation is determined by the 10-day

Leptocheirus plumulosus

sediment toxicity test (

i.e.,

ASTM E1367-92: “Standard Guide for Conducting 10-day Static Sediment Toxicity Tests With Marine and Estuarine Amphipods' (incorporated by reference and available from ASTM, 100 Bar Harbor Drive, West Conshohocken, PA 19428), supplemented with the preparation procedure specified in Appendix 3 of Subpart A of 40 CFR part 435). As originally proposed in February 1999 (64 FR 5503) and re-stated in April 2000 (65 FR 21549), EPA is promulgating the use of the ASTM E1367-92 method for compliance with this sediment toxicity BAT limitation.

Since the February 1999 proposal, EPA and other researchers conducted numerous 10-day

L. plumulosus

sediment toxicity tests on various SBF base fluids with natural and formulated sediments. Nearly all the SBF base fluids have lower sediment toxicity than diesel and mineral oil. Some SBF base fluids, however, show greater sediment toxicity than other SBF base fluids (

see

65 FR 21550; Docket No. W-98-26, Record No. IV.A.a.13). The base fluids meeting this limitation include vegetable esters, low viscosity esters, internal olefins, and some PAOs (

see

65

FR 21550; Docket No. W-98-26, Record No. IV.A.a.13).

EPA finds this limit to be technically available and economically achievable through product substitution because information in the rulemaking record supports the findings that vegetable esters, low viscosity esters, and internal olefins have performance characteristics enabling them to be used in the wide variety of drilling situations in offshore U.S. waters and meet today's promulgated limit.

EPA selected the C

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IO, which is the most popular drilling fluid in the GOM, as the basis for the sediment toxicity rate ratio limitation instead of the vegetable ester or low viscosity ester for several reasons: (1) EPA does not believe that vegetable esters can be used in all drilling situations; and (2) EPA does not have sufficient field testing information that low viscosity esters can be used in all drilling situations (

see

Section V.F.1.a). In addition, because of the uncertainty about ester performance, operators may not be encouraged to switch from OBFs or WBFs to SBF when properly installed and maintained. Specifically, vendor supplied data associated with these cuttings dryer deployments suggest that the overall cuttings dryer downtime (

i.e.,

time when cuttings dryer equipment is not operable) is approximately 1 to 2% (Docket No. W-98-26, Record No. IV.A.a.6). EPA finds this small downtime percentage as acceptable.

EPA discussed how it revised the BAT/NSPS-level solids control equipment configuration used in its analyses in the April 2000 NODA (65 FR 21559). EPA also discussed a range of management options regarding the BAT limitation for SBF retention on SBF-cuttings: (1) Two discharges from the BAT/NSPS-level solids control equipment configuration (

i.e.,

one discharge from the cuttings dryer and another discharge from the fines removal unit); (2) one discharge from the BAT/NSPS-level solids control equipment configuration (

i.e.,

one discharge from the cuttings dryer with the fines from the fines removal unit captured for zero discharge); and (3) zero discharge of SBF-cuttings. These three options are labeled as BAT/NSPS Option 1, BAT/NSPS Option 2, and BAT/NSPS Option 3, respectively. EPA estimates that 97% and 3% of the total cuttings are generated by cuttings dryer and fines removal unit, respectively.

EPA developed two numerical well averaged ROC limitations (

i.e.,

one for SBFs with the stock base fluid performance similar to esters and another for SBFs with the stock base fluid performance similar to C

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18

internal olefins) and based both of these ROC limitations on the technology of only one discharge from the cuttings dryer with the fines from the fines removal unit captured for zero discharge (

i.e.,

BAT/NSPS Option 2). The numerical well averaged ROC maximum limitation for SBFs (

i.e.,

9.4%) with the environmental characteristics of esters is based on a combination of data from horizontal centrifuge, vertical centrifuge, squeeze press, and High-G linear shaker cuttings dryer technologies. The numerical well averaged ROC maximum limitation for SBFs (

i.e.,

6.9%) with the environmental characteristics of C

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18

internal olefins is based on a combination of data from horizontal and vertical centrifuge cuttings dryer technologies. EPA estimates that operators, generally installing new equipment where none has been used in the past, will be able to choose from among the better technologies, designs, operating procedures, and maintenance procedures that EPA has considered to be among the best available technologies. EPA data demonstrates that operators properly using these cuttings dryer technologies will be able to comply with these final ROC numerical limitations. Data submitted to EPA show that operators using the vertical centrifuge and horizontal centrifuge are capable of achieving the lower ROC limitation (

i.e.,

6.9%). Data submitted to EPA also show that operators using the vertical centrifuge, horizontal centrifuge, squeeze press, and High-G linear shaker are capable of achieving the higher ROC limitation (

i.e.,

9.4%). More details on the observed performance of the individual technologies and details of calculation for the numerical limits are presented in the SBF Statistical Support Document and SBF Development Document.

EPA developed the two ROC limitations because EPA used a two part approach to control SBF-cuttings discharges. The first part is the control of which SBF are allowed for discharge through use of stock limitations (

e.g.,

sediment toxicity, biodegradation, PAH content, metals content) and discharge limitations (

e.g.,

diesel oil prohibition, formation oil prohibition, sediment toxicity, aqueous toxicity). The second part is the control of the quantity of SBF discharged with SBF-cuttings. As previously stated, EPA and industry sediment toxicity and biodegradation laboratory studies show that both vegetable esters and low viscosity esters have better environmental performance than all other SBF base fluids. However, because the technical availability of product substitution with esters was not demonstrated across the of

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