[Federal Register Volume 66, Number 14 (Monday, January 22, 2001)]
[Rules and Regulations]
[Pages 6850-6919]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 01-361]



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Part IV





Environmental Protection Agency





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40 CFR Parts 9 and 435



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; Final Rule

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

[[Page 6850]]


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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.

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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: 
<a href="/cdn-cgi/l/email-protection#167c797e786562797838757764736f5673667738717960"><span class="__cf_email__" data-cfemail="563c393e382522393878353724332f1633263778313920">[email protected]</span></a>. For additional economic information contact Mr. 
James Covington at (202) 260-5132 or send E-mail to: 
<a href="/cdn-cgi/l/email-protection#cdaea2bba4a3aab9a2a3e3a7aca0a8be8da8bdace3aaa2bb"><span class="__cf_email__" data-cfemail="fa99958c93949d8e9594d4909b979f89ba9f8a9bd49d958c">[email protected]</span></a>.

SUPPLEMENTARY INFORMATION:

Regulated Entities

    Entities potentially regulated by this action include:

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           Category                  Examples of regulated entities
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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 Secs. 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

[[Page 6851]]

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

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    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<INF>5</INF>), 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).

[[Page 6853]]

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

[[Page 6854]]

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

[[Page 6855]]

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

[[Page 6856]]

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

[[Page 6857]]

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<INF>4</INF>) 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,

[[Page 6858]]

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

[[Page 6859]]

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.

[[Page 6860]]

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

[[Page 6861]]

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

[[Page 6862]]

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.

[[Page 6863]]

    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<SUP>-6</SUP> 
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<INF>4</INF>), 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

[[Page 6864]]

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<INF>12</INF>-
C<INF>14</INF> vegetable esters of 2-hexanol and palm kernel oil, ``low 
viscosity'' C<INF>8</INF> 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<INF>12</INF>-C<INF>14</INF> vegetable esters of 2-hexanol and palm 
kernel oil, ``low viscosity'' C<INF>8</INF> 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<INF>ow</INF> 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<INF>ow</INF>) is used as a 
surrogate for estimating lipid/water partitioning). Moreover, 
hydrophobic chemicals (e.g., C<INF>16</INF>-C<INF>18</INF> internal 
olefins, various poly alpha olefins, and C<INF>18</INF> n-paraffins) 
with a log K<INF>ow</INF> 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

[[Page 6865]]

(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<INF>12</INF>-C<INF>14</INF> vegetable 
esters of 2-hexanol and palm kernel oil, ``low viscosity'' 
C<INF>8</INF> 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,

[[Page 6866]]

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<INF>50</INF> 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.

[[Page 6867]]

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<INF>50</INF> 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<INF>16</INF>-C<INF>18</INF> 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

[[Page 6868]]

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

[[Page 6869]]

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<INF>12</INF>-C<INF>14</INF> vegetable 
esters of 2-hexanol and palm kernel oil, and ``low viscosity'' 
C<INF>8</INF> 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<INF>16</INF> and C<INF>18</INF> alkenes; (2) linear alpha olefin 
(LAO) refers to a series of isomeric forms of C<INF>14</INF> and 
C<INF>16</INF> monoenes; (3) poly alpha olefin (PAO) refers to a mix 
mainly comprised of a hydrogenated decene dimer 
C<INF>20</INF>H<INF>62</INF> (95%), with lesser amounts of 
C<INF>30</INF>H<INF>62</INF> (4.8%) and C<INF>10</INF>H<INF>22</INF> 
(0.2%); (4) vegetable ester refers to a monoester of 2-ethylhexanol and 
saturated fatty acids with chain lengths in the range C<INF>8</INF>-
C<INF>16</INF>; and (5) ``low viscosity'' ester refers to an ester of 
natural or synthetic C<INF>8</INF> 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<INF>ow</INF> 3 to 3.5 and log K<INF>ow</INF>> 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<INF>16</INF>-C<INF>18</INF> IO. EPA also considered 
subcategorizing the final rule to determine when vegetable esters are 
not practical and when C<INF>16</INF>-C<INF>18</INF> 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

[[Page 6870]]

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  deg.F to perhaps 320  deg.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<INF>16</INF>-C<INF>18</INF> IOs; (2) 
can be used to formulate stable low viscosity ester-based SBFs up to 
300  deg.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<INF>16</INF>-C<INF>18</INF> 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<INF>16</INF>-C<INF>18</INF> 
IOs. Alternatively, this limitation could be expressed in terms of a 
``sediment toxicity ratio'' which is defined as 10-day LC<INF>50</INF> 
of C<INF>16</INF>-C<INF>18</INF> internal olefins divided by the 10-day 
LC<INF>50</INF> 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

[[Page 6871]]

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<INF>16</INF>-C<INF>18</INF> 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<INF>16</INF>-C<INF>18</INF> 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<INF>16</INF>-C<INF>18</INF> 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 offshore subcategory, EPA rejected the option 
of basing sediment toxicity and biodegradation stock limitations and 
standards on vegetable esters and low viscosity esters (see 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 a higher retention on cuttings 
discharge limitation to encourage operators to use esters when 
possible. EPA estimates that a higher retention on cuttings discharge 
limitation for esters is equivalent to the same level of control as a 
lower retention on cuttings discharge limitation for all other SBFs 
that have poorer sediment toxicity and biodegradation performances.
    In response to the April 2000 NODA, EPA received comments from an 
ester-based SBF manufacturer that EPA should create an incentive for 
operators to use ester-based SBFs by basing the ROC limitation for 
ester-based SBFs on baseline solids control equipment (e.g., primary 
and secondary shale shakers, fines removal unit) (Docket No. W-98-26, 
Record No. IV.A.a.7). In late comments, this same commentor claimed 
that a ROC limitation based on any cuttings dryer technology would not 
provide any incentive for the use of ester-based SBFs (Docket No. W-98-
26, Record No. IV.A.a.38). Further, they argued that the superior 
laboratory performance of these ester base fluids in terms of sediment 
toxicity and biodegradation justifies allowing them to be discharged 
with a ROC limitation based on baseline solids control equipment. EPA 
estimates that a ROC BAT limitation based on the baseline solids 
control equipment is above 15.3%.
    While EPA is willing to expand the technology basis to allow the 
use of less effective cuttings dryers for ester-based SBFs (e.g., 
squeeze press, High-G linear shakes), EPA is unwilling to entirely 
abandon the use of cuttings dryers for ester-based SBF drilling 
operations. EPA is unwilling to set a higher ROC limitation for SBFs 
with the environmental performance of ester-based SBFs based on 
baseline solids control technology because the environmental 
improvement resulting from the use of improved solids control 
technology (i.e., cuttings dryers) outweighs the incremental ester 
laboratory sediment toxicity and biodegradation performance over 
internal olefins. Cuttings dryers promote pollution prevention through 
increased re-use of drilling fluids and prevent

[[Page 6872]]

significant amounts of pollutants from being discharged to the ocean.
    EPA provides for variability from the long term average (LTA) of 
performance data from the candidate treatment technology or 
technologies. The LTA performance of the baseline solids control 
technology is 10.2%, as compared to the LTA of 4.8% based on data from 
all four cutting dryer technologies. 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. In balancing the 
environmental effects of these additional ester-based SBFs discharges 
controlled with the use of baseline solids control technology against 
the environmental effects of lower internal olefin-based SBFs 
discharges controlled with the use of cuttings dryers, EPA has 
concluded that the improvement in solids control technology leading to 
lower values of ROC is a more significant factor than laboratory data 
for ester base fluids showing lower sediment toxicity and higher 
biodegradation.
    EPA is also not convinced that the difference in ROC limitations 
provides no incentive to use ester-based SBFs, as the ester-based SBF 
manufacturer argues. EPA believes that the difference between 6.9% and 
9.4% could provide an incentive for operators to use ester-based SBFs. 
As operators have increasingly installed cuttings dryers in the GOM 
(over three dozen successful deployments in the last two years), and as 
any SBF discharger installs new technology to comply with the lower ROC 
limitation (i.e., 6.9%), operators may find that it is worthwhile to 
purchase ester-based SBFs in order to be able to operate with even a 
greater margin of flexibility under a limit of 9.4% as compared to 
6.9%.
    As this rule is performance based, EPA is not prohibiting the 
discharge of SBF-cuttings from the fines removal unit in order to 
comply with the base fluid retained on cuttings discharge BAT 
limitation. Operators are only required to show that the volume 
weighted average of all their SBF-cuttings discharges is below the 
discharge BAT limitation. EPA expects that most operators will be able 
to discharge cuttings from the cuttings dryer and fines removal unit 
and comply with this discharge BAT limitation. If, for example, the 
average retention of SBF on SBF-cuttings from a cuttings dryer is 
6.00%, the average retention of SBF on SBF-cuttings from a fines 
removal unit is 12.00%, and the fines are observed to comprise 3% of 
the total cuttings discharged, then the well average is 6.18% (i.e., 
(0.97) (6.00%) + (0.03)(12.00%) = 6.18%). If the well average for SBF 
retention from the cuttings dryer exceeds the discharge limit then in 
order to comply with this discharge BAT limitation all cuttings must be 
re-injected on-site or hauled to shore for land disposal. EPA finds 
that if this is the case, the limit is technologically available 
because operators have transported OBFs to shore since 1986 and have 
transported WBFs that do not meet the existing effluent limitations and 
standards since 1993.
    EPA finds that both ROC limitations (i.e., 6.9%, 9.4%) are 
technically available to the industry because they are based on product 
substitution and a statistical analysis of ROC performance from 
drilling conditions throughout offshore waters. The BAT limitations for 
controlling the amount of SBF discharged with SBF-cuttings are 
calculated such that nearly all well averages for retention are 
expected to meet these values using the selected technologies without 
any additional attention to design, operation, or maintenance. EPA data 
demonstrates that operators properly using these cuttings dryer 
technologies will be able to comply with these final ROC numerical 
limitations because: (1) These limits allow for variation in formation 
characteristics that may not exist in the United States; (2) 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 
considers to be among the best available technologies; and (3) 
operators may elect to use SBFs with the stock base fluid performance 
of esters and horizontal or vertical centrifuge cuttings dryers to 
achieve a ROC well average well below the 9.4% ROC limitation.
    Data used in the calculation of the numerical limits exclude 
retention results submitted without backup calculations (i.e., without 
raw retort data) and include data from drilling operations in foreign 
waters (e.g., Canada). EPA excluded ROC data without raw retort data 
(e.g., masses and volumes of cuttings samples and recovered liquids 
taken during the retort method by the field technician) due to concerns 
over data quality (e.g., no independent method to check data quality). 
EPA included ROC data from Canadian drilling operations to incorporate 
the variability of cuttings dryer performance in harder and less 
permeable formations that generally lead to higher ROC values. EPA 
estimates that the major factors leading to higher ROC values for all 
solids control equipment include: (1) Slower rates of penetration; (2) 
formations that are harder and less permeable; and (3) selection of 
certain drill bits. The Canadian ROC data come from formations that are 
generally much harder and less permeable than what is observed in the 
GOM. These harder formations generally lead to slower rates of 
penetration. The less permeable Canadian formations lead to fewer 
downhole losses of SBF. Downhole losses require the addition of fresh 
SBF to maintain volume requirements for the active mud system. These 
additions of fresh SBF to the active mud system help control the 
potential of build-up of fines. In addition, operators often use PDC 
drill bits in order to grind through the hard Canadian formations. This 
grinding action leads to smaller cuttings than is what is observed in 
the GOM. The smaller cuttings have more surface area for SBF than 
larger cuttings and generally have higher ROC values. Consequently, 
EPA's use of Canadian data in its analyses incorporate sufficient 
variability to model the formations in GOM, Offshore California, Cook 
Inlet, Alaska, and other offshore U.S waters where EPA does not have 
ROC data.
    EPA finds that both well-average discharge BAT ROC limitations 
(e.g., 6.9%, 9.4%) for base fluid on wet cuttings are economically 
achievable. According to EPA's analysis, in addition to reducing the 
discharge of SBFs associated with the cuttings, EPA estimates that this 
control will result in a net savings of $48.9 million ($1999) dollars 
per year. This savings results, in part, because the value of the SBF 
recovered is greater than the cost of installation of the improved 
solids control technology.
    EPA concluded that a zero discharge requirement for SBF-cuttings 
from

[[Page 6873]]

existing sources and the subsequent increase use of OBFs and WBFs would 
result in: (1) Unacceptable NWQIs; and (2) more pollutant loadings to 
the ocean due to operators switching from SBFs to less efficient WBFs 
(see Sections II.B and V.F). For these reasons, EPA rejected the BAT 
zero discharge option for SBF-cuttings from existing sources.
    EPA also requested comments in the April 2000 NODA (65 FR 21570) on 
the issue of rig compatibility with the installation of cuttings dryers 
(e.g., vertical or horizontal centrifuges, squeeze press mud recovery 
units, High-G linear shakers). EPA received general information on the 
problems and issues related to cuttings dryer installations from API/
NOIA stating that not all rigs are capable of installing cuttings 
dryers (Docket No. W-98-26, Record No. IV.A.a.13). In late comments, 
some industry commentors asserted that 48 of the 223 GOM drilling rigs 
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 (Docket No. W-98-26, Record No. IV.B.b.33). Upon a 
further, more extensive review of GOM rigs, these same commentors 
asserted that 30 of 234 GOM drilling rigs 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 (Docket No. W-98-
26, Record No. IV.B.b.34). EPA also received late comments from one 
operator, Unocal, stating that 36 of 122 Unocal wells drilled between 
late 1997 and mid-2000 were drilled with rigs that do not have 40 foot 
x  40 foot space available which they assert is necessary for a 
cuttings dryer installation (Docket No. W-98-26, Record No. IV.B.b.31). 
The API/NOIA rig survey and the Unocal rig survey identified most of 
the same rigs as unable to install cuttings dryers. However, two rigs 
(i.e., Parker 22, Nabors 802) identified in the Unocal rig survey as 
having no space for a cuttings dryer installation were identified in 
the API/NOIA rig survey as each having a previous cuttings dryer 
installation. Unocal requested in late comments that EPA subcategorize 
certain rigs from being subject to the retention limit or that these 
rigs be able to discharge SBFs using performance that reflects current 
shale shaker technology (Docket No. W-98-26, Record No. IV.A.a.36).
    Based on the record, EPA finds that current space limitations for 
cuttings dryers do not require a 40 foot  x  40 foot space. 
Specifically, EPA has in the record information gathered during EPA's 
October 1999 site visit and information supplied by API/NOIA, MMS, and 
equipment vendors. EPA received information from a drilling fluid 
manufacturer and cuttings dryer equipment vendor, M-I Drilling Fluids, 
stating that they are not aware of any GOM rig not capable of 
installing a cuttings dryer (Docket No. W-98-26, Record No. IV.B.b.32). 
Another cuttings dryer equipment vendor, JB Equipment, asserted that 
there are at most only a few rigs that pose questionable installation 
problems and that they have yet to survey a rig that they could not 
install a cuttings dryer (Docket No. W-98-26, Record No. IV.B.b.48). JB 
Equipment also stated that inexperience with cuttings dryer 
installations may inhibit the ability of operators or rig owners to 
properly judge whether a cuttings dryer can be installed. JB Equipment 
cited an example where the operator concluded that a cuttings dryer 
could not be installed on a rig (Nabors 803) while JB Equipment 
surveying efforts identified the cuttings dryer installation for the 
same rig as one of the simplest installations JB Equipment performs. 
MMS also concluded that rigs do not need a 40 foot  x  40 foot space to 
install a cuttings dryer and that, with the exception of a few jackup 
and platform rigs, there should not be any significant issues related 
to installing cuttings dryers on OCS drilling rigs (Docket No. W-98-26, 
Record No. IV.B.a.28). API/NOIA estimated that 150 square feet are 
required for a cuttings dryer installation in order to meet the ROC BAT 
limitation and NSPS (Docket No. W-98-26, Record No. IV.A.a.13). EPA 
also estimates that the minimum height clearance for a typical cuttings 
dryer installation is 6 feet (see SBF Development Document). The API/
NOIA estimate is based on the installation of a horizontal centrifuge 
cuttings dryer (i.e., MUD-6). The Unocal estimate is based on the 
vertical centrifuge cuttings dryer and is also characterized by other 
industry representatives and MMS as too high (Docket No. W-98-26, 
Record No. IV.B.b.34; Record No. IV.B.a.28). EPA's estimate of a 
typical vertical centrifuge installation is 15 feet  x  15 feet (i.e., 
225 square feet) with a minimum height clearance of 11 feet (see SBF 
Development Document). EPA based the ROC BAT limitation and NSPS (e.g., 
6.9%) on the use of both these cuttings dryers for SBFs with the stock 
limitations of C<INF>16</INF>-C<INF>18</INF> IOs. Based on comments 
from operators, equipment vendors, and MMS, EPA believes that most of 
these shallow water rigs have the requisite 150-225 square feet 
available to install a cuttings dryer (see SBF Development Document). 
Therefore, EPA finds that operators are not required to have a 1,600 
square foot space for a cuttings dryer installation in order to meet 
the ROC BAT limitation and NSPS. Proper spacing and placement of 
cuttings dryers in the solids control equipment system should prevent 
installation problems.
    Because of the large discrepancy between EPA's record information 
and the space requirements asserted by the commenter (1,600 square feet 
versus EPA's 225 square feet + 11 feet in height for the vertical 
centrifuge or 150 square feet + 6 feet in height for the horizontal 
centrifuge--MUD-6), EPA does not necessarily believe that there are as 
many wells that cannot install cuttings dryers as the commentor 
(Unocal) claims. Further, based on scant detail supporting these 
assertions, and their lateness in the process, EPA has no basis upon 
which to assess them or verify them.
    Moreover, EPA does not believe that it has enough information to 
reasonably subcategorize these facilities, nor did it have time to 
provide public notice of how it would define such a subcategory, given 
the court-ordered deadline for this rule. EPA does not believe that 
basing a subcategory by specifying a space requirement alone (e.g. 
operators that do not have a certain amount of deck space available on, 
below or adjacent to the deck would not be subject to this requirement) 
would be sufficient to prevent operators from configuring their other 
equipment in a manner that would enable them to fit into the 
subcategory. Such an exception might also lead to operators to make 
other assertions justifying that they should be included (e.g., that 
while they have a certain amount of space available, safety reasons 
prevent placement of the technology on the rig). Without a solution to 
these issues, EPA is concerned that such a subcategorization would 
potentially be too broad and be unworkable.
    For these reasons, EPA believes that the appropriate way to handle 
these concerns is through the fundamentally different factors (FDF) 
variance process. This process, provided for under CWA section 301(n), 
would allow operators to submit supporting data and information to EPA 
and would give the public the opportunity to comment on that data to 
determine whether an FDF is truly warranted for that drilling facility. 
EPA has authority over owners and operators, who are both dischargers, 
but the NPDES regulations require the operator to apply for the NPDES 
permit: ``When a facility or activity is owned by one person but is 
operated by another person, it is the operator's duty to obtain

[[Page 6874]]

a permit,'' (see 40 CFR 122.21(b)). Thus, mobile drill rig 
``operators'' as dischargers can apply for FDFs (see 40 CFR 125.32; 
122.21(b)).
    EPA notes that the ROC limitations and standards do not preclude 
the use of SBFs if an operator cannot meet them if the operator can 
meet zero discharge through re-injection or shipment to shore. 
Historically, dischargers have used water-based fluids in shallow water 
wells and this may also be an option. EPA considers controlled WBF 
discharges preferable to uncontrolled SBF discharges. EPA examined the 
NWQIs associated with these zero discharge operations as acceptable 
(see SBF Development Document). The NWQIs of zero discharge for the 
shallow water wells are much smaller that those associated for the 
entire region covered by this rule. Further, while a SBF-cuttings 
discharge option with adequate controls is preferred over the zero 
discharge option for SBF-cuttings in U.S. Offshore waters, a SBF-
cuttings discharge option with inadequate controls is not preferred 
over zero discharge. The retention limit is a very important control 
because it 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. In short, EPA does not view existing shale 
shaker technology (or performance of other technology equivalent to 
shale shaker technology) to constitute the appropriate level of control 
under BAT or BADT (NSPS).
    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.C). EPA has decided to 
control accumulated solids and wash water under the discharge 
requirements for cuttings associated with SBFs. The amount of SBF base 
fluid discharged with discharged accumulated solids will be estimated 
using procedures in Appendix 7 to subpart A of 40 CFR part 435 and 
incorporated into the base fluid retained on cuttings numeric 
limitation or standard. The source of the pollutants in the accumulated 
solids and associated wash water are drill cuttings and drilling fluid 
solids (e.g., barite). The drill cuttings and drilling fluid solids can 
be prevented from discharge with SBF-cuttings due to equipment design 
(e.g., sand traps, sumps) or improper maintenance of the equipment 
(e.g., failing to ensure the proper agitation of mud pits). EPA agrees 
with commentors that the discharge of SBF associated with accumulated 
solids in the SBF active mud system and the associated wash water is 
normally a one-time operation performed at the completion of the SBF 
well (e.g., cleaning out mud pits and solids control equipment).
    The quantity of SBF typically discharged with accumulated solids 
and wash water is relatively small. The SBF fraction in the 75 barrels 
of accumulated solids is approximately 25% and generally only very 
small quantities of SBF are contained in the 200 to 400 barrels of 
associated equipment wash water. Current practice is to retain 
accumulated solids for zero discharge or recover free oil from 
accumulated solids prior to discharge. Since current practice is to 
recover free oil and discharge accumulated solids, the controlled 
discharge option for SBF-cuttings represents current practice and is 
economically achievable. Moreover, recovering free oil from accumulated 
solids prior to discharge has no unacceptable NWQIs. EPA defines 
accumulated solids and wash water as associated with drill cuttings. 
Therefore, operators will control these SBF-cuttings wastes using the 
SBF stock limitations and cuttings discharge limitations. As compliance 
with EPA's SBF stock limitations and cuttings discharge limitations 
does not require the processing of all SBF-cuttings wastes through the 
solids control technologies (e.g., shale shakers, cuttings dryers, 
fines removal units), operators may or may not elect to process 
accumulated solids or wash water through the solids control 
technologies.
    EPA is also promulgating a set of BMPs for operators to use that 
demonstrates compliance with the numeric ROC limitation and therefore 
reduces the retort monitoring otherwise required to determine 
compliance with the numeric ROC limitation. This option combines the 
set of BMPs that represent current practice with BMPs that are 
associated with the use of improved solids control technology. This 
option is technologically available and economically achievable for the 
same reasons that apply to compliance with the ROC numerical 
limitations. Examples of BMPs that represent current practices are, for 
example, use of mud guns, proper mixing procedure, elimination of 
settling places for accumulated solids. Examples of BMPs associated 
with the use of the new solids control technology are, for example, 
operating cuttings dryers in accordance with the manufacturer's 
specifications and maintaining a certain mass flux. If operators elect 
to use this BMP option, they will be required to demonstrate compliance 
through limited retort monitoring of cuttings and additional BMP 
paperwork. Paperwork requirements are detailed in Appendix 7 of subpart 
A of 40 CFR part 435. Paperwork cost and burden estimates are detailed 
in Section IX.D of the preamble.
    d. Sediment Toxicity of SBF Discharged with Cuttings. 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 to control the 
maximum sediment toxicity of the SBF discharged with cuttings. This BAT 
limitation controls the sediment toxicity of the SBF discharged with 
cuttings as a non-conventional pollutant parameter and as an indicator 
for other pollutants in the SBF discharged with cuttings. Some of the 
toxic, priority, and non-conventional pollutants in the SBF discharged 
with cuttings may include: (1) The base fluids such as enhanced mineral 
oils, internal olefins, linear alpha olefins, poly alpha olefins, 
paraffinic oils, C<INF>12</INF>-C<INF>14</INF> vegetable esters of 2-
hexanol and palm kernel oil, ``low viscosity'' C<INF>8</INF> esters, 
and other oleaginous materials; (2) barite which is known to generally 
have trace contaminants of several toxic heavy metals such as mercury, 
cadmium, arsenic, chromium, copper, lead, nickel, and zinc; (3) 
formation oil which contains toxic and priority pollutants such as 
benzene, toluene, ethylbenzene, naphthalene, phenanthrene, and phenol; 
and (4) additives such as emulsifiers, oil wetting agents, filtration 
control agents, and viscosifiers.
    The sediment toxicity of the SBF discharged with cuttings is 
measured by the modified 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) using a natural sediment or 
formulated sediment, 96-hour testing period, and Leptocheirus 
plumulosus as the test organism. EPA is today promulgating a sediment 
toxicity limitation for the SBF discharged with cuttings at the point 
of discharge that would only allow the discharge of SBF-cuttings using 
SBFs as toxic or less toxic, but not more toxic, than C<INF>16</INF>-
C<INF>18</INF>

[[Page 6875]]

IOs SBFs. Alternatively, this limitation could be expressed in terms of 
a ``SBF sediment toxicity ratio'' which is defined as 96-hour 
LC<INF>50</INF> of C<INF>16</INF>-C<INF>18</INF> internal olefins SBF 
divided by the 96-hour LC<INF>50</INF> of the SBF being discharged with 
cuttings at the point of discharge. EPA is promulgating a SBF sediment 
toxicity ratio of less than 1.0.
    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. As previously stated, establishing 
discharge limits on toxicity encourages the use of less toxic drilling 
fluids and additives. The modifications to the 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.
    The promulgated sediment toxicity limitation would be achievable 
through product substitution. EPA anticipates that the base fluids 
meeting the sediment toxicity limitation would include vegetable 
esters, low viscosity esters, and internal olefins. The reference 
C<INF>16</INF>-C<INF>18</INF> IOs SBF will be formulated to meet the 
specifications in Table 1 and also contained in Appendix 8 of subpart A 
of 40 CFR part 435. The sediment toxicity discharge limitation is 
technically and economically achievable because it is based on 
currently available base fluids that can be used and are used across 
the wide variety of drilling situations found in U.S. offshore waters. 
EPA estimates minimal monitoring costs associated with this limitation. 
Additionally, the sediment toxicity discharge limitation will not lead 
to an increase of NWQIs.

         Table 1.--Properties for Reference C<INF>16</INF>-C<INF>18</INF> IOs SBF Used in Discharge Sediment Toxicity Testing
----------------------------------------------------------------------------------------------------------------
                                                                                          Reference C<INF>16</INF>-C<INF>18</INF> ISOs
Mud weight of SBF discharged with cuttings (pounds per gallon)   Reference C<INF>16</INF>-C<INF>18</INF> IOs    SBF synthetic to water
                                                                SBF (pounds per gallon)         ratio (%)
----------------------------------------------------------------------------------------------------------------
8.5-11........................................................                      9.0                    75/25
11-14.........................................................                     11.5                    80/20
> 14..........................................................                     14.5                    85/15
================================================================================================================
Plastic Viscosity (PV), centipoise (cP).......................  .......................                    12-30
Yield Point (YP), pounds/100 sq. ft...........................  .......................                    10-20
10-second gel, pounds/100 sq. ft..............................  .......................                     8-15
10-minute gel, pounds/100 sq. ft..............................  .......................                    12-30
Electrical stability, V.......................................  .......................                    > 300
----------------------------------------------------------------------------------------------------------------

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

    The general approach followed by EPA for developing NSPS options 
was to evaluate the best demonstrated SBFs and processes for control of 
priority toxic, non-conventional, and conventional pollutants. 
Specifically, EPA evaluated the technologies used as the basis for BPT, 
BCT and BAT. The Agency considered these options as a starting point 
when developing NSPS options because the technologies used to control 
pollutants at existing facilities are fully applicable to new 
facilities.
    EPA has not identified any more stringent treatment technology 
option which it considered to represent NSPS level of control 
applicable to the SBF-cuttings wastestream. Further, EPA has made a 
finding of no barrier to entry based upon the establishment of this 
level of control for new sources. Therefore, EPA is promulgating that 
NSPS be established equivalent to BPT and BAT for conventional, 
priority, and non-conventional pollutants. EPA concluded that NSPS are 
technologically and economically achievable for the same reasons that 
BAT is available and BPT is practical. EPA also concluded that NWQIs 
are reduced under the selected NSPS for new wells due to the increased 
efficiency of SBF drilling.
    EPA concluded that a zero discharge requirement for SBF-cuttings 
from new sources and the subsequent increased use of OBFs and WBFs 
would result in: (1) unacceptable NWQIs; and (2) more pollutant 
loadings to the ocean due to operators switching from SBFs to less 
efficient WBFs (see Sections II.B and V.F).
    For the same reasons that the BAT limitations promulgated in 
today's rule are technologically and economically achievable, the 
promulgated NSPS are also technologically and economically achievable. 
EPA's analyses show that under the SBF zero discharge option for all 
areas as compared to current practice as a basis for new source 
standards there would be an increase of 3.4 million pounds of cuttings 
annually shipped to shore for disposal in NOW sites and an increase of 
10.2 million pounds of cuttings annually injected. This zero discharge 
option would lead to an increase in annual fuel use of 18,067 BOE and 
an increase in annual air emissions of 528 tons. Finally, the SBF zero 
discharge option for the GOM would lead to an increase of 7.5 million 
pounds of WBF-cuttings being discharged to U.S. Offshore waters. This 
pollutant loading increase is a result of operators in U.S. Offshore 
waters (in the GOM) switching from efficient SBF drilling to less 
efficient WBF drilling. EPA found these levels of NWQIs unacceptable 
and rejected the NSPS zero discharge option for SBF-cuttings from new 
sources, except in Coastal Cook Inlet, Alaska.

H. PSES and PSNS Technology Options

    EPA is not establishing pretreatment standards for the facilities 
covered by this rule. Based on information in the record, EPA has not 
identified any existing offshore or Cook Inlet coastal oil and gas 
extraction facilities that discharge SBF and SBF-cuttings to publicly 
owned treatment works (POTWs), nor are any new facilities projected to 
direct these wastes in such manner.

[[Page 6876]]

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

    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 (see Section II.A.7). 
The BMP alternatives to numeric limitations and standards in this final 
rule are directed, among other things, at preventing or otherwise 
controlling leaks, spills, and discharges of toxic and hazardous 
pollutants in SBF cuttings wastes (see 65 FR 21569 for a list of the 
toxic and hazardous pollutants controlled by these BMPs).
    As discussed in the April 2000 NODA (65 FR 21568), EPA considered 
three options for the final rule for the BAT limitation and NSPS 
controlling SBF retained on discharged cuttings: (1) A single numeric 
discharge limitation with an accompanying compliance test method; (2) 
allowing operators to choose either a single numeric discharge 
limitation with an accompanying compliance test method, or as an 
alternative, a set of BMPs that employs limited cuttings monitoring; or 
(3) allowing operators to choose either a single numeric discharge 
limitation with an accompanying compliance test method or an 
alternative set of BMPs that employ no cuttings monitoring. Under the 
third BMP option for SBF-cuttings (i.e., cuttings discharged and not 
monitored), EPA also considered whether to require as part of the BMP 
option, the use of a cuttings dryer as representative of BAT/NSPS or to 
make the use of a cuttings dryer optional.
    EPA selects the second BMP option (i.e., allowing operators to 
choose either a single numeric discharge limitation with an 
accompanying compliance test method, or as an alternative, a set of 
BMPs that employs limited cuttings monitoring) in the final rule. EPA 
selects this option as it provides for a reasonable level of 
flexibility and is based on quantifiable performance measures. EPA 
analyses show that cuttings monitoring for the first third of the SBF 
footage drilled for a SBF well interval is a reliable indicator of the 
remaining two-thirds of the SBF-interval (see SBF Statistical Support 
Document; Docket No. W-98-26, Record No. III.B.a.18; Record No. 
III.B.b.15). Procedures for demonstrating compliance with the selected 
BMP option are given in Appendix 7 to subpart A of part 435.
    For the final rule, EPA did not have enough data from across a wide 
variety of drilling conditions (e.g., formation, water depth, rig size) 
to demonstrate that BMPs without cuttings monitoring are equivalent to 
a numeric ROC limitation or standard. EPA is also concerned that a set 
of BMPs without cuttings monitoring is not as objective to enforce. 
This is because with a numeric limitation or with the selected BMP 
option with reduced cuttings monitoring, operators will need to keep 
records demonstrating compliance with the numeric limitation. By 
contrast, under a BMP option with no numeric limit, there is no 
objective performance measure. This presents a particular problem 
offshore, where real-time inspections are not as practical as on land 
based industries. Therefore, EPA rejected the third BMP option and 
cuttings dryer sub-option for SBF-cuttings (i.e., allowing operators to 
choose either a single numeric discharge limitation with an 
accompanying compliance test method or an alternative set of BMPs that 
employ no cuttings monitoring). EPA concluded that BMP option one and 
BMP option two demonstrate the same level of compliance with the well 
averaged ROC limitation and standard (see SBF Statistical Support 
Document). Therefore, EPA selected BMP option two over BMP option one 
to provide operators with greater flexibility to demonstrate compliance 
with the well averaged ROC limitation and standard.
    The BMP option promulgated in this final rule includes information 
collection requirements that are intended to control the discharges of 
SBF in place of numeric effluent limitations and standards. These 
information collection requirements include, for example: (1) Training 
personnel; (2) analyzing spills that occur; (3) identifying equipment 
items that might need to be maintained, upgraded, or repaired; (4) 
identifying procedures for waste minimization; (4) performing 
monitoring (including the operation of monitoring systems) to establish 
equivalence with a numeric cuttings retention limitation and to detect 
leaks, spills, and intentional diversion; and (5) generally to 
periodically evaluate the effectiveness of the BMP alternatives.
    BMP option two also requires operators to develop and, when 
appropriate, amend plans specifying how operators will implement BMP 
option two, and to certify to the permitting authority that they have 
done so in accordance with good engineering practices and the 
requirements of the final regulation. The purpose of those provisions 
is, respectively, to facilitate the implementation of BMP option two on 
a site-specific basis and to help the regulating authorities to ensure 
compliance without requiring the submission of actual BMP Plans. 
Finally, the recordkeeping provisions are intended to facilitate 
training, to signal the need for different or more vigorously 
implemented BMP alternatives, and to facilitate compliance assessment. 
Details on burden and cost estimates associated with these additional 
paperwork requirements are discussed in Section IX.D.

VI. Costs and Pollutant Reductions for Final Regulation

A. Compliance Costs

    EPA has analyzed the compliance costs and incremental compliance 
costs or savings beyond current industry practices and requirements, as 
well as pollutant loadings and incremental loadings or reductions, EPA 
has performed these analyses for the Gulf of Mexico, offshore 
California, and coastal Cook Inlet, Alaska, for baseline (current) 
costs and three control option costs. (Compliance costs were not 
developed for other offshore regions in Alaska where oil and gas 
production activity exists because discharges of drill cuttings is not 
expected to occur in these areas.) The three technology-based options 
considered are: (1) BAT/NSPS Option 1 (controlled discharge option with 
discharges from the cuttings dryer and fines removal unit); (2) BAT/
NSPS Option 2 (controlled discharge option with discharges from the 
cuttings dryer but not the fines removal unit); and (3) BAT/NSPS Option 
3 (Zero Discharge Option). Compliance costs/savings and pollutant 
increases/reductions are based on: (1) Projected annual drilling 
activity in the three geographic regions; (2) model well volumes and 
waste characteristics; and (3) technology and monitoring costs.
    The compliance cost analysis begins with the development of defined 
populations of wells on a regional and well-type basis, develops per-
well estimates from an analysis of line-item costs, and then aggregates 
costs into total regional and well-type costs by applying per well 
costs to appropriate populations of wells. EPA estimates baseline 
compliance costs for current industry waste management practices and 
for compliance with each regulatory option. EPA then calculated 
incremental compliance costs, which reflect the difference between 
compliance costs for a regulatory option and baseline compliance costs 
and the net compliance costs or savings which incorporate the costs 
along with savings realized by recovering drilling fluids and more 
efficient drilling. Tables 2 and

[[Page 6877]]

3, for existing and new sources respectively, list the total annual 
baseline costs, compliance costs, incremental compliance costs, cost 
savings, and net incremental compliance costs, calculated for each 
geographic area and regulatory option.
1. Large Volume Discharges

BILLING CODE 6560-50-U

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2. Small Volume Discharges
    As previously stated, EPA learned that SBF is controlled with zero 
discharge at the drill floor, in the form of vacuums and sumps to 
retrieve spilled fluid and associated wash water. 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.
    No additional costs were considered for controlling the minor 
spills of SBF (e.g.,  5 gallons spilled during each drill string 
connection or disconnection) at the drill floor as: (1) Zero discharge 
practices for recovering SBF at the drill floor during drilling are the 
current practice; and (2) current practice is also to recover free SBF 
from the wash water used at the drill floor. Additionally, since 
current practice is to first recover free SBF from accumulated solids 
and discharge the accumulated solids with wash water, no additional 
costs were

[[Page 6881]]

considered for controlling these discharges.
    EPA did not select zero discharge for management of these 
accumulated solids and associated wash water. EPA is defining these 
wastes as being associated with SBF-cuttings and subject to the same 
requirements as other SBF discharges associated with SBF-cuttings. In 
particular, the final rule requires operators to first recover free oil 
from any accumulated solids or associated wash water prior to 
discharging the accumulated solids and associated wash water. These 
practices are related to the current BPT limitations (i.e., no 
discharge of free oil) and current industry practice using solids 
control equipment in order to comply with the no free oil (sheen test) 
and SPP toxicity requirements. Accordingly, the requirement to recover 
free oil from accumulated solids and associated wash water prior to 
discharge is technologically and economically achievable with no 
additional NWQIs. Retort monitoring will also be performed on the 
accumulated solids and the retort monitoring results will be 
incorporated into the overall well-average SBF retained on cuttings 
value as described in Appendix 7 of Subpart A of 40 CFR 435.

B. Pollutant Reductions

    The methodology for estimating pollutant loadings and incremental 
pollutant loadings (reductions) effectively parallels that of the 
compliance cost analysis. The pollutant loadings analysis uses data 
from EPA and industry sources that quantify the pollutant 
characteristics of drilling fluids and cuttings waste streams 
(typically in, or converted to, a per barrel basis). Waste volumes for 
the four model well types (DWD, DWE, SWD, SWE) are coupled with these 
per barrel pollutant quantities to obtain per well estimates of 
pollutant loadings. These per well estimates are then coupled with the 
same well count data as used in the cost analysis to derive well type 
and aggregate regional pollutant loadings for the baseline and all 
options. Similar to the cost analysis, incremental loadings (or 
removals) are obtained by difference between the estimated loadings of 
each option less baseline loadings, at both the BAT and NSPS level of 
control. This methodology is presented in more detail in the SBF 
Development Document.
    The loadings and non-water quality impacts of wastes subject to 
zero discharge limitations by this rule are important factors in its 
development. Zero discharge wastes have two fates: they are injected 
into sub-seabed formations onsite or they are transported to shore for 
disposal via land farming or injection. The allocation of zero 
discharge wastes between onsite injection versus onshore disposal 
follow the same well type and regional assumptions as were used for the 
cost analysis. Zero discharge loadings (removals) are determined 
identically to discharge loadings; they are presented in detail in the 
Development Document and are summarized below.
    Table 4 presents a summary of industry-wide results, by region, for 
BAT baseline loadings, both discharge options, and the zero discharge 
option, as well as their incremental loadings (removals). Table 5 
presents this information for new sources.
    The BCT cost test evaluates the reasonableness of BCT candidate 
technologies as measured from BPT level compliance costs and pollutant 
reductions. The proposed BCT level of regulatory control is equivalent 
to the BPT level of control for both the discharge options and the zero 
discharge option. If there is no incremental difference between BPT and 
BCT, there is no cost to BCT and thus the option passes both BCT cost 
tests.

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[[Page 6883]]



      Table 5.--Summary Annual SBF Pollutant Loadings, New Sources
                            [In pounds/year]
------------------------------------------------------------------------
                                                 SBF pollutant loadings
               Technology basis                   (reductions)--Gulf of
                                                         Mexico
------------------------------------------------------------------------
Baseline/Current Practice Technology Loadings:
    Discharge with LTA of 10.2% SBF ROC.......               17,405,127
    Discharge of WBF and cuttings.............               92,903,606
    Discharge of OBF..........................                        0
                                               -------------------------
      Total Baseline Loadings.................              110,308,733
                                               =========================
Technology Option Loadings:
    BAT/NSPS Option 1.........................
    Discharge with LTA of 4.03% SBF ROC.......               20,241,106
    Discharge of WBF and cuttings.............               87,462,923
    Discharge of OBF..........................                        0
                                               -------------------------
      Total NSPS 1 Loadings...................              107,704,029
                                               =========================
    BAT/NSPS Option 2.........................
    Discharge with LTA of 3.82% SBF ROC.......               19,722,488
    Discharge of WBF and cuttings.............               87,462,923
    Discharge of OBF..........................                        0
                                               -------------------------
      Total NSPS 2 Loadings...................              107,185,411
                                               =========================
    BAT/NSPS Option 3--Zero Discharge.........
    Discharge of SBF..........................                        0
    Discharge of WBF and cuttings.............              100,387,607
    Discharge of OBF..........................                        0
                                               -------------------------
      Total NSPS 3 Loadings...................              100,387,607
                                               =========================
Incremental Technology Option Loadings
 (Reductions):
    BAT/NSPS Option 1: Discharge with 4.03%                  (2,604,704)
     retention of SBF on cuttings.............
    BAT/NSPS Option 2: Discharge with 3.82%                  (3,123,322)
     retention of SBF on cuttings.............
    BAT/NSPS Option 3: Zero Discharge of SBF-                (9,921,126) 
     wastes via land disposal or onsite
     injection................................
------------------------------------------------------------------------
Note: EPA estimates the following GOM WBF/OBF/SBF new sources: Baseline--
  38/2/20; BAT/NSPS Option 1 & 2--35/1/24; and BAT/NSPS Option 3--42/15/
  3. EPA estimates no new sources for Offshore California or Cook Inlet,
  AK.
Note: The following terms are used in this table: long-term average
  (LTA) and retention on cuttings (ROC).

VII. Economic Impacts of Final Regulation

    EPA evaluated the economic effects of the options considered for 
today's regulation. The methodology and results are presented in detail 
in the SBF Economic Analysis (EPA-821-B-00-012). The following 
discussion presents a summary of that analysis and its conclusions. 
Small business impacts are summarized below and in Section IX.B. 
Environmental justice issues are summarized in Section IV.C.

A. Impacts Analysis

    EPA examined the potential impacts of the rule several ways: 
effects on drilling well costs, changes to financial performance of 
drilling facilities and production, impacts on small firms, and 
secondary impacts. The economic methodology used to examine potential 
impacts on drilling well costs, firms, and secondary impacts is the 
same as that used for the February 1999 proposal (see 64 FR 5521-5527; 
February 1999 proposal Economic Analysis (EPA-821-B-98-020)).
    In response to comments and new data, EPA developed a series of 
economic models for existing and new deep water projects in the Gulf of 
Mexico similar to those used for the Offshore and Coastal rules (see 58 
FR 12454-12512 and 61 FR 66086-66130). This additional analysis is 
discussed in the April 2000 NODA (65 FR 21558). The models focus on the 
deep water Gulf because it is the region with the highest level of 
current drilling with and future interest in drilling with SBFs. The 
economic models are based on a cash flow approach. Revenues are based 
on an assumed price of oil, current and projected production of oil and 
gas, well production decline rates, and royalty rates. Operating costs 
are based on an assumed cost per BOE produced. The models are based on 
data from MMS and industry (see Summary of Data to be Used In Economic 
Modeling for more details on the methodology, data, and parameters on 
which the models are based and how the models were constructed (Docket 
No. W-98-26, Section III.G of the Rulemaking Record)) and SBF Economic 
Analysis, Appendix A. EPA received no comments on this NODA with 
respect to the economic methodology or the data.
    The costs and revenues are compared yearly and the project is 
assumed to run for 30 years or to shut in when operating costs exceed 
revenues. That is, the economic models have differing lifetimes 
according to project characteristics and each model may have a 
shortened lifetime as a result of incremental costs. The model then 
calculates the lifetime of the project, total production, and the net 
present value of the operation (net income of the operation over the 
life of the project in terms of today's dollars), which includes the 
net operating earnings, taxes, expenditures on drilling, other capital 
expenditures, etc. A positive net present value means that the project 
is a good investment. In these cases, the return is greater than the 
discount rate,

[[Page 6884]]

which represents the opportunity cost of capital. If the net present 
value is negative, it means that money would have been better invested 
elsewhere. For existing projects, the model uses current operations; 
all expenditures in prior years, such as exploration, delineation, and 
infrastructure development costs are considered sunk costs and are not 
addressed. For new projects, the model uses data and parameters about 
timing of the various phases of exploration, delineation and 
development, along with cost estimates about costs incurred during 
these phases to compute a full lifetime financial model of these 
projects.
    Each model is run twice--with and without the change due to 
pollution control. The models support changes in both directions--i.e., 
costs or savings. If a model shows the net present value of a project 
to be positive in the baseline, but would have a negative net present 
value under any of the regulatory options, some or all of the wells 
would not be drilled. This difference between baseline and 
postcompliance would generate production impacts.
    The likely outcome of today's rule is an overall savings associated 
with the ability to discharge SBF cuttings (see Section VI.A). The cost 
model (which provides the input to the economic models) projects that 
the savings exceed any incremental costs of compliance in the 
aggregate. EPA does not expect the alternate higher ROC limitation and 
standard for drilling fluids with the stock base fluid performance of 
esters to affect costs. EPA expects that operators will likely use 
ester-based SBFs for the increased flexibility and not for any economic 
benefits. The results of the economic models indicate no adverse 
impacts on drilling well costs (exploratory or developmental), project 
lifetime, or production for both BAT and NSPS projects. There are no 
adverse impacts on firms, employment, trade, or inflation.

B. Small Business Analysis

    Although today's rule will not have a significant economic impact 
on a substantial number of small entities (see Section VII.A), EPA 
assessed the impacts of the rule on small businesses. The small 
business analysis is described more fully in Chapter 6 of the SBF 
Economic Analysis.
    The small business definitions and the methodology were outlined in 
the April 2000 NODA and the February 1999 Proposal Economic Analysis 
and have not changed. Briefly, EPA relied on the Small Business 
Administration's size standards to determine whether a firm is a small 
business. If EPA could not find employment or revenue data to confirm a 
firm's size, it was classified as ``potentially'' small. EPA identified 
40 small and potentially small firms. As noted in the previous 
paragraph, today's rule results in cost savings, and EPA projects no 
adverse impacts on small businesses.

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

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

    EPA conducted various analyses to assess the impact of the final 
regulation on water quality, sediment quality, and human health. In 
general, EPA has found that no adverse impacts are expected from 
controlled discharges of SBFs.

B. Water Quality Modeling

    In order to assess the impacts of potential SBF discharges to the 
receiving waters, EPA conducted pore water, water column, and sediment 
guidelines analyses. EPA calculated pollutant concentrations for both 
the water column and pore water and compared them to the respective EPA 
recommended marine water quality criteria or to applicable state 
standards to determine the nature and magnitude of any projected water 
quality exceedances. Details of the analyses and results are presented 
in the final SBF Environmental Assessment.
    EPA included the discharge of WBFs in the engineering analyses (see 
Section II.A). Environmental impacts such as water column, pore water, 
fish tissue and human health risk analyses were not estimated for the 
discharge of WBFs versus the use and discharge of SBF cuttings. 
However, industry has provided information that drilling is 
significantly more efficient using SBFs rather than WBFs because hole 
volumes with SBFs are approximately 1.8 times smaller. Therefore, the 
pollutant loadings of appropriately controlled SBF discharge are less 
than pollutant loadings associated with controlled WBF discharge.
1. Water Column Water Quality Analyses
    There are no water quality criteria exceedances in the water column 
for any of the regulatory options being considered including the ROC 
option based on data from all four cuttings dryer technologies for 
drilling fluids with the sediment toxicity and biodegradation 
characteristics of ester-based SBFs which results in a slightly higher 
LTA. Also, no Alaska state water quality standards are exceeded under 
the discharge options in Cook Inlet, Alaska.
2. Pore Water Quality Analyses
    As described above in Section III.D.1, the addition of several 
seabed survey data changed the estimated SBF sediment concentration at 
100 meters (328 feet) as used in the pore water quality analyses. The 
revised analyses estimate that baseline (or BPT) pore water pollutant 
concentrations at 100 meters from the discharge exceed recommended 
water quality criteria for the heavy metal, chromium, for two model 
well types, shallow water exploratory and deep water exploratory. There 
are no pore water exceedances of any of the Alaska state water quality 
standards for potential Cook Inlet, Alaska discharges. Also, there are 
no pore water exceedances under the controlled SBF discharges (i.e., 
BAT/NSPS Options 1 and 2) including the ROC option based on data from 
all four cuttings dryer technologies for drilling fluids with the 
sediment toxicity and biodegradation characteristics of ester-based 
SBFs which results in a slightly higher LTA.
3. Sediment Guidelines Analyses
    The EPA proposed sediment guidelines for the protection of benthic 
organisms assesses potential benthic impacts of certain metals. The 
revised analyses, based on revised pore water concentrations, result in 
2 exceedances only under the baseline (or BPT) conditions. There are no 
sediment guidelines exceedances under controlled SBF discharge 
conditions (i.e., BAT/NSPS Options 1 and 2) including the ROC option 
based on data from all four cuttings dryer technologies for drilling 
fluids with the sediment toxicity and biodegradation characteristics of 
ester-based SBFs which results in a slightly higher LTA.

C. Human Health Effects Modeling

    The human health risk analyses were revised to incorporate changes 
to the fish consumption rates (see Section III.D.b). The revised 
analyses show no risk to human health.

D. Seabed Surveys

    EPA reviewed the seabed surveys submitted during public comment to 
the April 2000 NODA. As previously stated, EPA used data from two 
surveys drilling six wells with SBFs in the environmental assessment 
analyses. Additionally, EPA also received information on the on-going 
joint Industry/MMS GOM seabed survey. The Industry/MMS workgroup has

[[Page 6885]]

completed the first two cruises of the four cruise study (see Section 
III.D.1). Outside of a 50-100' radius from the drilling facility, no 
visible cuttings accumulations (large or small) were detected at any of 
the drilling facility survey sites.

E. Energy Impacts

    As described in Sections III.E and IV.E, EPA included additional 
data and revised several parameters in estimating energy impacts of the 
final SBF rule. EPA estimated the amount of fuel required, expressed as 
barrels of oil equivalents per year (BOE/yr), to operate the equipment 
associated with each of the regulatory options as well as the fuel 
consumed by daily rig operations. EPA also estimated the current energy 
requirements of WBF discharge in order to determine the relative 
decrease in impacts of SBF versus WBF use. EPA does not expect the 
alternate higher ROC limitation and standard for drilling fluids with 
the stock base fluid performance of esters to affect energy impacts 
because equipment used under the ester option (e.g., shale shakers, 
cuttings dryer, fines removal unit) has the same or similar energy 
requirements. The results of the energy impact analysis are presented 
in Tables 6 and 7 for existing and new sources, respectively.

                      Table 6.--Incremental Summary Annual Energy Impacts, Existing Sources
----------------------------------------------------------------------------------------------------------------
                                                          Energy impacts: Reductions (Increases)<SUP>a</SUP> fuel use (BOE/
                                                                                    yr)
                    Technology basis                     -------------------------------------------------------
                                                             Gulf of      Offshore     Cook Inlet,
                                                             Mexico      California        AK           Total
----------------------------------------------------------------------------------------------------------------
BAT/NSPS Option 1: Discharge with LTA of 4.03% SBF ROC..      202,146             0            19       202,165
BAT/NSPS Option 2: Discharge with LTA of 3.82% SBF ROC..      195,124             0             0       195,124
BAT/NSPS Option 3: Zero Discharge of SBF-wastes via land     (346,459)       (6,138)       (6,067)     (358,664) 
 disposal or onsite injection...........................
----------------------------------------------------------------------------------------------------------------
<SUP>a</SUP> Annual fuel usage reductions or increases are incremental to baseline/current practice (i.e., discharge of SBF-
  cuttings at 10.2% ROC in the GOM and zero discharge in Offshore California and Cook Inlet, AK).
 
 Note: BOE = Barrels of Oil Equivalent.
Note: The following terms are used in this table: long-term average (LTA) and retention on cuttings (ROC).


    Table 7.--Incremental Summary Annual Energy Impacts, New Sources
------------------------------------------------------------------------
                                                     Energy impacts:
               Technology basis                  Reductions (increases)<SUP>a</SUP>
                                                    fuel use (BOE/yr)
------------------------------------------------------------------------
BAT/NSPS Option 1: Discharge with LTA of 4.03%                     6330
 SBF ROC......................................
BAT/NSPS Option 2: Discharge with LTA of 3.82%                     5693
 SBF ROC......................................
BAT/NSPS Option 3: Zero Discharge of SBF-                       (18,067) 
 wastes via land disposal or onsite injection.
------------------------------------------------------------------------
<SUP>a</SUP> Annual fuel usage reductions or increases are incremental to baseline/
  current practice (i.e., discharge of SBF-currings at 10.2% ROC in the
  GOM).
 
 Note: BOE = Barrels of Oil Equivalent.
Note: The following terms are used in this table: long-term average
  (LTA) and retention on cuttings (ROC).
Note: EPA estimates no new sources for Offshore California or Cook
  Inlet, AK.

F. Air Emission Impacts

    EPA calculated the air emissions, expressed as short tons per year, 
resulting from activities associated with each of the regulatory 
options. Air emissions are a function of the: (1) Type of fuel burned 
(e.g., natural gas or diesel); and (2) amount of fuel consumed as 
determined from the length of equipment operation and the fuel 
consumption rate. The methodology and modeling parameters parallel that 
of the energy impact analysis as the amount of fuel consumed is the 
basis for the air emissions analysis. Therefore, the air emissions 
analysis includes the estimate of emissions of daily rig operations and 
an estimate of WBF drilling operation air emissions. EPA does not 
expect the alternate higher ROC limitation and standard for drilling 
fluids with the stock base fluid performance of esters to affect air 
emissions because equipment used under the ester option (e.g., shale 
shakers, cuttings dryer, fines removal unit) has the same or similar 
air emissions. The results of the air emission analysis are presented 
in Tables 8 and 9 for existing and new sources, respectively.

                      Table 8.--Incremental Summary Annual Air Emissions, Existing Sources
----------------------------------------------------------------------------------------------------------------
                                                          Annual Air Emission Reductions (Increases) <SUP>a</SUP> (tons/yr)
                                                         -------------------------------------------------------
                    Technology basis                         Gulf of      Offshore     Cook Inlet,
                                                             Mexico      California        AK           Total
----------------------------------------------------------------------------------------------------------------
BAT/NSPS Option 1: Discharge with LTA of 4.03% SBF ROC..        3,172             0             0         3,172
BAT/NSPS Option 2: Discharge with LTA of 3.82% SBF ROC..        3,074             0            (1)        3,073
BAT/NSPS Option 3: Zero Discharge of SBF-wastes via land       (5,414)          (94)          (94)       (5,602) 
 disposal or onsite injection...........................
----------------------------------------------------------------------------------------------------------------
<SUP>a</SUP> Annual air emissions reductions or increases are incremental to baseline/current practice (i.e., discharge of
  SBF-cuttings at 10.2% ROC in the GOM and zero discharge in Offshore California and Cook Inlet, AK).
 
 Note: 1 ton = 2000 lbs.
Note: The following terms are used in this table: long-term average (LTA) and retention cuttings (ROC).


[[Page 6886]]


Table 9.--Incremental Summary Air Emissions, New Sources--Gulf of Mexico
------------------------------------------------------------------------
                                                             Annual air
                                                              emissions
                     Technology basis                         reduction
                                                             (increases)
                                                             <SUP>a</SUP> (tons/yr)
------------------------------------------------------------------------
BAT/NSPS Option 1: Discharge with LTA of 4.03% SBF ROC....         (136)
BAT/NSPS Option 2: Discharge with LTA of 3.82% SBF ROC....         (145)
BAT/NSPS Option 3: Zero Discharge of SBF-wastes via land          (528)
 disposal or onsite injection.............................
------------------------------------------------------------------------
<SUP>a</SUP> Annual air emissions reductions or increases are incremental to
  baseline/current practice (i.e., discharge of SBF-cuttings at 10.2%
  ROC in the GOM).
 
 Note: 1 ton = 2000 lbs.
Note: The following terms are used in this table: long-term average
  (LTA) and retention on cuttings (ROC).
Note: EPA estimates no new sources for Offshore California or Cook
  Inlet, AK.

G. Air Emissions Monetized Human Health Benefits

    EPA estimated emissions associated with each of the regulatory 
options as part of the NWQI analyses. The pollutants considered in the 
NWQI analyses are nitrogen oxides ( NO<INF>X</INF>), volatile organic 
carbon (VOC), particulate matter (PM), sulfur dioxide (SO<INF>2</INF>), 
and carbon monoxide (CO). Of these pollutants, EPA monetized the human 
health benefits or impacts associated with VOC, PM, and SO<INF>2</INF> 
emissions using the methodology presented in the Environmental 
Assessment of the Final Effluent Limitations Guidelines and Standards 
for the Pharmaceutical Manufacturing Industry (EPA-821-B-98-008). Each 
of these pollutants have human health impacts and reducing these 
emissions can reduce these impacts.
    Several VOCs exhibit carcinogenic and systemic effects and VOCs, in 
general, are precursors to ground-level ozone, which negatively affects 
human health and the environment. PM impacts include aggravation of 
respiratory and cardiovascular disease and altered respiratory tract 
defense mechanisms. SO<INF>2</INF> impacts include nasal irritation and 
breathing difficulties in humans and acid deposition in aquatic and 
terrestrial ecosystems.
    The unit values (in 1990 dollars) are $489 to $2,212 per megagram 
(Mg) of VOC; $10,823 per Mg of PM; and $3,516 to $4,194 per Mg of 
SO<INF>2</INF>. Using the Engineering News Record Construction Cost 
Index (see www.enr.com/cost/costcci.asp) these conversion factors are 
scaled up using the ratio of 6060:4732 (1999$:1990$). EPA does not 
expect the alternate higher ROC limitation and standard for drilling 
fluids with the stock base fluid performance of esters to affect 
monetized benefits because equipment used under the ester option (e.g., 
shale shakers, cuttings dryer, fines removal unit) has the same or 
similar air emissions. Following is a summary of the monetized benefits 
for each of the regulatory options for both existing and new sources.

BILLING CODE 6560-50-U

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[GRAPHIC] [TIFF OMITTED] TR22JA01.160

H. Solid Waste Impacts

    EPA calculated the amount of waste cuttings that would be land 
disposed, injected onshore, and/or injected onsite in each regulatory 
scenario, and determined that there would be a considerable reduction 
in the amount of drill cuttings land disposed and injected with the 
implementation of a controlled discharge option for SBF-cuttings.
    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 annual increase of 35 million 
pounds of cuttings shipped to shore for disposal in non-hazardous 
oilfield waste (NOW) sites and an increase of 166 million pounds of 
cuttings 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.
    Additionally, EPA's analyses show that under the SBF-cuttings zero 
discharge option as compared to current practice, for GOM new sources, 
there would be an annual increase of 3.4 million pounds of drill 
cuttings shipped to shore for disposal in NOW sites and an increase of 
10.2 million pounds of drill cuttings injected. These zero discharge 
options for SBF-cuttings would lead to an increase in annual fuel use 
of 18,067 BOE and an increase in annual air emissions of 528 tons. 
Finally, the SBF-cuttings zero discharge option in the GOM would lead 
to an increase of 7.5 million pounds of WBF-cuttings being discharged 
to U.S. Offshore waters. Again, this pollutant loading increase is a 
result of GOM operators switching from efficient SBF drilling to less 
efficient WBF drilling.

I. Other Factors

    EPA also considered the impact of the effluent limitations 
guidelines and

[[Page 6889]]

standards on safety. EPA has identified two safety issues related to 
drilling fluids: (1) Deleterious vapors generated by organic materials 
in drilling fluids; and (2) waste hauling activities that increase the 
risk of injury to workers.
1. Vapors Generated by Organic Materials in Drilling Fluids
    One of the key concerns in exploration and production projects is 
the exposure of wellsite personnel to vapors generated by organic 
materials in drilling fluids (Docket No. W-98-26, Record No. III.D.12). 
Areas on the drilling location with the highest exposure potentials are 
sites near solids control and open pits. These areas are often enclosed 
in rooms and ventilated to prevent unhealthy levels of vapors from 
accumulating. If the total volume of organic vapors can be reduced then 
any potential health effects will also be reduced regardless of the 
nature of the vapors.
    Generally speaking the aromatic fraction of the vapors is the most 
toxic to the mammalian system. The high volatility and absorbability 
through the lungs combined with their high lipid solubility serve to 
increase their toxicity. OBFs have a high aromatic content and vapors 
generated from using these drilling fluids include aromatics (e.g., 
alkybenzenes, naphthalenes, and alkyl-naphthalenes), alkanes (e.g., C 
<INF>7</INF> -C <INF>18</INF> straight chained and branched), and 
alkenes. Some minerals oils also generate vapors that contain the same 
types of chemical compounds, but generally at lower concentrations, as 
those found in the diesel vapors (e.g., aromatics, alkanes, cyclic 
alkanes, and alkenes). Because SBF are manufactured from compounds with 
specifically defined compositions, the subsequent compound can exclude 
toxic aromatics. Consequently, toxic aromatics can be excluded from the 
vapors generated by using SBFs.
    In general, SBFs (e.g., esters, LAOs, PAOs, IOs) generate much 
lower concentrations of vapors than do OBFs (Docket No. W-98-26, Record 
No. III.D.12). Moreover, the vapors generated by these SBFs are less 
toxic than traditional OBFs because they do not contain aromatics.
2. Waste Hauling Activities
    Industry has commented in previous effluent guidelines, such as the 
Coastal Subcategory Oil and Gas Extraction and Development ELG, that a 
zero discharge requirement would increase the risk of injury to workers 
due to increased waste hauling activities. These activities include 
vessel trips to and from the drilling facility to haul waste, transfer 
of waste from the drilling facility onto a service vessel, and transfer 
in port onto a barge or dock.
    EPA has identified and reviewed additional data sources to 
determine the likelihood that imposition of a zero discharge limitation 
on cuttings contaminated with SBF could increase risk of injury due to 
additional waste hauling demands. The sources of safety data are the 
U.S. Coast Guard (USCG), the Minerals Management Service (MMS), the 
American Petroleum Institute (API), and the Offshore Marine Service 
Association (OMSA). The following is a summary of the findings from 
this review.
    The data indicate that there are reported incidents that are 
associated with the collection, hauling, and onshore disposal of wastes 
from offshore. However, the data do not distinguish whether any of 
these incidents can be attributed to specific waste management 
activities.
    Most offshore incidents are due to human error or equipment 
failure. The rate at which these incidents occur will not be changed 
significantly by increased waste management activities. However, if the 
number of man hours and/or equipment hours are increased, there will be 
more reportable incidents given an unchanged incident rate. These 
potential increases may be offset by reduced incident rates through 
increased training or equipment maintenance and inspection; but these 
changes cannot be predicted. One indication that training and 
maintenance can reduce incident rates is a 1998 API report entitled 
``1997 Summary of U.S. Occupational Injuries, Illnesses, and Fatalities 
in the Petroleum Industry,'' which established that injury incident 
rates have been decreasing over the last 14 years. If this decrease 
continues, there should be no increase in the number of safety 
incidents due to a requirement to haul SBF-contaminated cuttings to 
shore for disposal. The details of this analysis are available in a 
technical support document in the rule record for today's final rule.

IX. Regulatory Requirements

A. Executive Order 12866: Regulatory Planning and Review

    Under Executive Order 12866 (58 FR 51735 (October 4, 1993)), the 
Agency must determine whether the regulatory action is ``significant'' 
and therefore subject to OMB review and the requirements of the 
Executive Order. The Order defines ``significant regulatory action'' as 
one that is likely to result in a rule that may:
    (1) Have an annual effect on the economy of $100 million or more or 
adversely affect in a material way the economy, a sector of the 
economy, productivity, competition, jobs, the environment, public 
health or safety, or State, local, or tribal governments or 
communities;
    (2) Create a serious inconsistency or otherwise interfere with an 
action taken or planned by another agency;
    (3) Materially alter the budgetary impact of entitlements, grants, 
user fees, or loan programs or the rights and obligations of recipients 
thereof; or
    (4) Raise novel legal or policy issues arising out of legal 
mandates, the President's priorities, or the principles set forth in 
the Executive Order.
    Pursuant to the terms of Executive Order 12866, it has been 
determined that this rule is a ``significant regulatory action.'' As 
such, this action was submitted to OMB for review. Changes made in 
response to OMB suggestions or recommendations are documented in the 
public record.

B. Regulatory Flexibility Act (RFA), as amended by the Small Business 
Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 USC 601 et. 
seq.

    The RFA generally requires an agency to prepare a regulatory 
flexibility analysis of any rule subject to notice and comment rule 
requirements under the Administrative Procedure Act or any other 
statute unless the agency certifies that the rule will not have a 
significant economic impact on a substantial number of small entities. 
Small entities include small businesses, small organizations, and small 
governmental jurisdictions.
    For purposes of assessing the impacts of today's rule on small 
entities, small entity is defined as: (1) A small business with fewer 
than 500 employees for oil and gas production operators and less than 
$5 million per year in revenues for oil and gas services providers 
(i.e., the definitions from SBA's size standards); (2) a small 
governmental jurisdiction that is a government of a city, county, town, 
school district, or special district with a population of less than 
50,000; and (3) a small organization that is any not-for-profit 
enterprise which is independently owned and operated and is not 
dominant in its field. After considering the economic impact of today's 
final rule on small entities, I certify that this action will not have 
a significant economic impact on a substantial number of small 
entities. Today's rule affects small businesses only; there are no 
impacts on small governmental jurisdictions or small organizations.

[[Page 6890]]

    In determining whether a rule has a significant economic impact on 
a substantial number of small entities, the impact of concern is any 
significant adverse economic impact on small entities. Since the 
primary purpose of the regulatory flexibility analysis is to identify 
and address regulatory alternatives ``which minimizes any significant 
economic impact of the proposed rule on small entities.'' 5 U.S.C. 
Sections 603 and 604. Thus, an agency may certify that a rule will not 
have a significant economic impact on a substantial number of small 
entities if the rule relieves regulatory burden, or otherwise has a 
positive economic effect on all of the small entities subject to the 
rule.
    EPA projects that today's rule will result in operational savings 
and will have no adverse economic impacts. These conclusions apply to 
all firms, both large and small. EPA estimates that between five and 40 
small businesses (between five and 40% of all firms) are covered by 
today's rule. If the small businesses are using SBF and continue to do 
so, or if they switch to SBF, they need to comply with today's effluent 
limitations. EPA estimates that the operational savings associated with 
an allowable SBF-cuttings discharge will result in an economic 
advantage, contrasted to other SBF-cuttings regulatory scenarios. EPA 
selected the controlled discharge option which will allow operators to 
use of SBF in place of OBF and WBFs. Using SBFs in place of OBFs 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 costs and NWQI such as fuel use, air emissions, and land 
disposal of OBFs. Use of SBFs in place of WBFs would also lead to: (1) 
a decrease in costs and NWQIs due to the decreased length of the 
drilling project; and (2) a per well decrease of pollutants discharged 
due to improved technical performance of SBFs. 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. Further, after 
considerable study, EPA's record indicates that there will be no 
significant economic impacts to any small entity subject to the rule. 
The SBF Economic Analysis describes these results in more detail. We 
have therefore conducted that today's final rule will relieve 
regulatory burden for all small entities.

C. Submission to Congress and the General Accounting Office

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the 
Small Business Regulatory Enforcement Fairness Act of 1996, generally 
provides that before a rule may take effect, the agency promulgating 
the rule must submit a rule report, which includes a copy of the rule, 
to each House of the Congress and to the Comptroller General of the 
United States. EPA will submit a report containing this rule and other 
required information to the U.S. Senate, the U.S. House of 
Representatives, and the Comptroller General of the United States prior 
to publication of the rule in the Federal Register. A major rule cannot 
take effect until 60 days after it is published in the Federal 
Register. This action is not a ``major rule'' as defined by 5 U.S.C. 
804(2). This rule will be effective February 21, 2001.

D. Paperwork Reduction Act

    The Office of Management and Budget (OMB) has approved the 
information collection requirements contained in this rule under the 
provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and 
has assigned OMB control number 2040-0230.
    The information collection requirements are related to the optional 
use of Best Management Practices (BMPs) in order to reduce SBF-cuttings 
monitoring. Operators that elect to not use the BMP alternative are not 
subject to the information collection requirements in today's final 
rule. BMPs are inherently pollution prevention practices. BMPs may 
include the universe of pollution prevention encompassing production 
modifications, operational changes, material substitution, materials 
and water conservation, and other such measures. BMPs include methods 
to prevent toxic and hazardous pollutants from reaching receiving 
waters. Because BMPs are most effective when organized into a 
comprehensive facility BMP Plan, EPA is requiring operators to complete 
a BMP Plan when they select the BMP alternative.
    The BMP alternative requires operators to develop and, when 
appropriate, amend plans specifying how operators will implement the 
specified BMP alternative, and to certify to the permitting authority 
that they have done so in accordance with good engineering practices 
and the requirements of the regulation. The purpose of those provisions 
is, respectively, to facilitate the implementation of BMP alternative 
on a site-specific basis and to help the regulating authorities to 
ensure compliance without requiring the submission of actual BMP Plans. 
Finally, the recordkeeping provisions are intended to facilitate 
training, to signal the need for different or more vigorously 
implemented BMPs, and to facilitate compliance assessment.
    The information collection requirements in the final rule include, 
for example: (1) Training personnel; (2) analyzing spills that occur; 
(3) identifying equipment items that might need to be maintained, 
upgraded, or repaired; (4) identifying procedures for waste 
minimization; (5) performing monitoring (including the operation of 
monitoring systems) to establish equivalence with a numeric cuttings 
retention limitation and to detect leaks, spills, and intentional 
diversion; and (6) generally to periodically evaluate the effectiveness 
of the BMP alternatives.
    EPA does not expect that any confidential business information or 
trade secrets will be required from oil and gas extraction operators as 
part of this ICR. If information submitted in conjunction with this ICR 
were to contain confidential business information, the respondent has 
the authority to request that the information be treated as 
confidential business information. All data so designated will be 
handled by EPA pursuant to 40 CFR part 2. This information will be 
maintained according to procedures outlined in EPA's Security Manual 
Part III, Chapter 9, dated August 9, 1976. Pursuant to section 308(b) 
of the CWA, effluent data may not be treated as confidential.
    EPA estimated the burden and costs to the regulated community 
(approximately 67 SBF well drilling facilities annually) and EPA, the 
NPDES permit control authority, for data collection and record keeping 
associated with implementation of the BMP alternative. EPA estimates 
the public reporting burden for the selected BMP option as 787 hours 
per respondent per year (i.e., (16,750 initial hours/3 years + 47,168 
annual hours/year)/67 SBF well operators). EPA also estimated the 
annual burden for EPA Regions, the NPDES permit controlling 
authorities, to review BMPs and ensure compliance. EPA estimates that 
essentially all of the SBF discharges will occur in Federal offshore 
waters or in Cook Inlet, Alaska, where EPA Region X retains NPDES 
permit controlling authority. The EPA Regional burden for reviewing BMP 
Plans is estimated at 380 hours per year (i.e., (536 initial hours/3 
years + 201 annual hours/year)).
    EPA estimates the public reporting costs as $24,058 per respondent 
per year (i.e., ($1,235,313 initial costs/3 years + $1,200,138 annual 
costs/year)/67 SBF well operators). The EPA Regional costs for 
reviewing BMP Plans is estimated at approximately $12,149 per year 
(i.e.,

[[Page 6891]]

($17,152 initial costs/3 years + $6,432 annual costs/year)).
    Burden means the total time, effort, or financial resources 
expended by persons to generate, maintain, retain, or disclose or 
provide information to or for a Federal agency. This includes the time 
needed to review instructions; develop, acquire, install, and utilize 
technology and systems for the purposes of collecting, validating, and 
verifying information, processing and maintaining information, and 
disclosing and providing information; adjust the existing ways to 
comply with any previously applicable instructions and requirements; 
train personnel to be able to respond to a collection of information; 
search data sources; complete and review the collection of information; 
and transmit or otherwise disclose the information.
    An Agency may not conduct or sponsor, and a person is not required 
to respond to a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for EPA's 
regulations are listed in 40 CFR part 9 and 48 CFR chapter 15. EPA is 
amending the table in 40 CFR part 9 of currently approved ICR control 
numbers issued by OMB for various regulations to list the information 
requirements contained in this final rule.

E. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public 
Law 104-4, establishes requirements for Federal agencies to assess the 
effects of their regulatory actions on State, local, and tribal 
governments and the private sector. Under section 202 of the UMRA, EPA 
generally must prepare a written statement, including a cost-benefit 
analysis, for proposed and final rules with ``Federal mandates'' that 
may result in expenditures to State, local, and tribal governments, in 
the aggregate, or to the private sector, of $100 million or more in any 
one year. Before promulgating an EPA rule for which a written statement 
is needed, section 205 of the UMRA generally requires EPA to identify 
and consider a reasonable number of regulatory alternatives and adopt 
the least costly, most cost-effective or least burdensome alternative 
that achieves the objectives of the rule. The provisions of section 205 
do not apply when they are inconsistent with applicable law. Moreover, 
section 205 allows EPA to adopt an alternative other than the least 
costly, most cost-effective or least burdensome alternative if the 
Administrator publishes with the final rule an explanation why that 
alternative was not adopted. Before EPA establishes any regulatory 
requirements that may significantly or uniquely affect small 
governments, including tribal governments, it must have developed under 
section 203 of the UMRA a small government agency plan. The plan must 
provide for notifying potentially affected small governments, enabling 
officials of affected small governments to have meaningful and timely 
input in the development of EPA regulatory proposals with significant 
Federal intergovernmental mandates, and informing, educating, and 
advising small governments on compliance with the regulatory 
requirements.
    EPA has determined that this rule does not contain a Federal 
mandate that may result in expenditures of $100 million or more for 
State, local, and tribal governments, in the aggregate, or the private 
sector in any one year. EPA projects that the effect of the rule will 
be a operational savings. EPA has estimated this savings at $48.9 
million (1999$, post-tax). Thus, today's rule is not subject to the 
requirements of Sections 202 and 205 of the UMRA.
    EPA has determined that this rule contains no regulatory 
requirements that might significantly or uniquely affect small 
governments. EPA projects that no small governments will be affected by 
this rule as small governments are not engaged in oil and gas 
extraction operations in offshore and coastal waters or in issuing 
NPDES permits for oil and gas extraction operations in offshore and 
coastal waters. Thus, today's rule is not subject to the requirements 
of section 203 of the UMRA.

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

    Under Executive Order 13084 EPA may not issue a regulation that is 
not required by statute, that significantly or uniquely affects the 
communities of Indian Tribal governments, and that imposes substantial 
direct compliance costs on those communities, unless the Federal 
government provides the funds necessary to pay the direct compliance 
costs incurred by the tribal governments, or EPA consults with those 
governments. If EPA complies by consulting, Executive Order 13084 
requires EPA to provide to the Office of Management and Budget, in a 
separately identified section of the preamble to the rule, a 
description of the extent of EPA's prior consultation with 
representatives of affected tribal governments, a summary of the nature 
of their concerns, and a statement supporting the need to issue the 
regulation. In addition, Executive Order 13084 requires EPA to develop 
an effective process permitting elected officials and other 
representatives of Indian tribal governments ``to provide meaningful 
and timely input in the development of regulatory policies on matters 
that significantly or uniquely affect their communities.''
    Today's rule does not significantly or uniquely affect the 
communities of Indian tribal governments nor does it impose substantial 
direct compliance costs on them. EPA has determined that currently, no 
communities of Indian tribal governments are affected by this rule as 
Indian tribal governments are not engaged in oil and gas extraction 
operations in offshore and coastal waters or in issuing NPDES permits 
for oil and gas extraction operations in offshore and coastal waters. 
Accordingly, the requirements of section 3(b) of Executive Order 13084 
do not apply to this rule.

G. Executive Order 13132: Federalism

    Executive Order 13132, entitled ``Federalism'' (64 FR 43255, August 
10, 1999), requires EPA to develop an accountable process to ensure 
``meaningful and timely input by State and local officials in the 
development of regulatory policies that have federalism implications.'' 
``Policies that have federalism implications'' is defined in the 
Executive Order to include regulations that have ``substantial direct 
effects on the States, on the relationship between the national 
government and the States, or on the distribution of power and 
responsibilities among the various levels of government.''
    This final rule does not have federalism implications. It will not 
have substantial direct effects on the States, on the relationship 
between the national government and the States, or on the distribution 
of power and responsibilities among the various levels of government, 
as specified in Executive Order 13132. The rule establishes effluent 
limitations and standards imposing requirements that apply to oil and 
gas extraction operations in offshore and coastal waters. EPA has 
determined that there are no oil and gas extraction operations in 
offshore and coastal waters that are owned and operated by State or 
local governments. Therefore, this rule will not impose any 
requirements on State or local governments. Further, the rule will not 
affect State governments' authority to implement CWA and UIC permitting 
programs. In fact, the final rule may reduce administrative costs on 
States that have authorized NPDES programs because although these 
States must incorporate the new limitations and

[[Page 6892]]

standards in new and revised NPDES permits, they no longer will need to 
make Best Professional Judgement (BPJ) determinations regarding the 
appropriate level of technology control. We recognize that there may be 
a small administrative cost to the State of Alaska to assist EPA Region 
10 in determining whether Coastal Cook Inlet, Alaska, operators qualify 
for the SBF-cuttings zero discharge exemption (see Section V.F). Thus, 
Executive Order 13132 does not apply to this rule.

H. National Technology Transfer and Advancement Act

    As noted in the proposed rule (64 FR 5528), section 12(d) of the 
National Technology Transfer and Advancement Act (NTTAA) of 1995, Pub 
L. 104-113 section 12(d) (15 U.S.C. 272 note), directs EPA to use 
voluntary consensus standards in its regulatory activities unless to do 
so would be inconsistent with applicable law or otherwise impractical. 
Voluntary consensus standards are technical standards (e.g., materials 
specifications, test methods, sampling procedures, and business 
practices) that are developed or adopted by voluntary consensus 
standard bodies. The NTTAA directs EPA to provide Congress, through the 
Office of Management and Budget (OMB), explanations when the Agency 
decides not to use available and applicable voluntary consensus 
standards.
    This rule involves technical standards. The rule requires 
dischargers to measure for two metals, PAH content (as phenanthrene), 
sediment toxicity, aqueous toxicity, biodegradation rate, formation oil 
content, and base fluid retained on cuttings. EPA performed a search to 
identify potentially applicable voluntary consensus standards that 
could be used to measure the parameters in today's rule. EPA did locate 
several voluntary consensus standards that required modification for 
inclusion in the final rule. EPA considered public comments on the 
proposed rule and worked with stakeholders, including the industry 
sponsored Synthetic Based Muds Research Consortium (SBMRC), to modify 
or develop new standards for various parameters (i.e., sediment 
toxicity, biodegradation rate, PAH content (as phenanthrene), formation 
oil content, base fluid retained on cuttings). EPA has decided to use 
modified versions of the following voluntary consensus standards: (1) 
EPA Method 1654A; (2) ASTM E-1367-92; (3) ISO 11734:1995; and (4) API 
Recommended Practice 13B-2. As indicated by industry comments on the 
February 1999 proposal and April 2000 NODA, industry stakeholders 
support the use of these modified voluntary consensus standards (see 
Docket No. W-98-26, Record No. IV.A.a.13).

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

    The Executive Order 13045, ``Protection of Children from 
Environmental Health Risks and Safety Risks'' (62 FR 19885, April 23, 
1997), applies to any rule that: (1) Is determined to be ``economically 
significant'' as defined under Executive Order 12866, and (2) concerns 
an environmental health or safety risk that EPA has reason to believe 
may have a disproportionate effect on children. If the regulatory 
action meets both criteria, the Agency must evaluate the environmental 
health or safety effects of the planned rule on children and explain 
why the planned regulation is preferable to other potentially effective 
and reasonably feasible alternatives considered by the Agency. This 
final rule is not subject to E.O. 13045 because it is not 
``economically significant'' as defined under Executive Order 12866, 
and because the rule does not concern an environmental health or safety 
risk that may have a disproportionate effect on children.

J. Executive Order 13158: Marine Protected Areas

    Executive Order 13158 (65 FR 34909, May 31, 2000) requires EPA to 
``expeditiously propose new science-based regulations, as necessary, to 
ensure appropriate levels of protection for the marine environment.'' 
EPA may take action to enhance or expand protection of existing marine 
protected areas and to establish or recommend, as appropriate, new 
marine protected areas. The purpose of the executive order is to 
protect the significant natural and cultural resources within the 
marine environment, which means ``those areas of coastal and ocean 
waters, the Great Lakes and their connecting waters, and submerged 
lands thereunder, over which the United States exercises jurisdiction, 
consistent with international law.''
    EPA believes that this final rule is consistent with the objectives 
of the Executive Order to protect the ocean environment. By encouraging 
the use of appropriately controlled SBFs in the place of more toxic 
OBFs, the ocean will be protected from the effects of spills of OBFs 
and from the effects of disposal of OBFs onshore. By encouraging the 
use of appropriately controlled SBFs over WBFs, there will much less 
drilling waste generated and discharged to the ocean per well and the 
drilling waste discharged will be far less toxic and will biodegrade at 
a much faster rate than those of traditional drilling fluids.

X. Regulatory Implementation

    Upon promulgation of these regulations, the effluent limitations 
for the appropriate subcategory must be applied in all Federal and 
State NPDES permits issued to affected direct dischargers in the oil 
and gas extraction industry. This section discusses the relationship of 
upset and bypass provisions, variances and modifications, and 
monitoring requirements.

A. Implementation of Limitations and Standards

    Upon the promulgation of these regulations, all new and reissued 
Federal and State NPDES permits issued to direct dischargers in the oil 
and gas extraction industry must include the effluent limitations for 
the appropriate subcategory. Permit writers should be aware that EPA 
has now finalized revisions to 40 CFR 122.44(a) which could be 
particularly relevant to the development of NPDES permits for the oil 
and gas extraction point source category (see 65 FR 30989, May 15, 
2000). As finalized, the revision would require that permits have 
limitations for all applicable guidelines-listed pollutants but allows 
for the waiver of sampling requirements for guideline-listed pollutants 
on a case-by-case basis if the discharger can certify that the 
pollutant is not present in the discharge or present in only background 
levels from intake water with no increase due to the activities of the 
dischargers. New sources and new dischargers are not eligible for this 
waiver for their first permit term, and monitoring can be re-
established through a minor modification if the discharger expands or 
changes its process. Further, the permittee must notify the permit 
writer of any modifications that have taken place over the course of 
the permit term and, if necessary, monitoring can be reestablished 
through a minor modification.

B. Upset and Bypass Provisions

    A ``bypass'' is an intentional diversion of waste streams from any 
portion of a treatment facility. An ``upset'' is an exceptional 
incident in which there is unintentional and temporary noncompliance 
with technology-based permit effluent limitations because of factors 
beyond the reasonable control of the permittee. EPA's regulations 
concerning bypasses and upsets are set forth at 40 CFR 122.41(m) and 
(n), and 40 CFR 403.16 (upset) and 403.17

[[Page 6893]]

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

C. Variances and Modifications

    The CWA requires application of the effluent limitations and 
standards established pursuant to section 301, 304, 306, or the 
pretreatment standards of section 307 to all direct and indirect 
dischargers. However, section 301(n) provides for the modification of 
these national requirements in a limited number of circumstances. 
Moreover, the Agency has established administrative mechanisms to 
provide an opportunity for relief from the application of national 
effluent limitations guidelines and pretreatment standards for 
categories of existing sources for priority, conventional and non-
conventional pollutants (e.g., fundamentally different factor 
variances, removal credits).
    The Fundamentally Different Factors (FDF) variances considers those 
facility specific factors which a permittee may consider to be uniquely 
different from those considered in the formulation of an effluent 
limitations guidelines as to make the limitation inapplicable. An FDF 
variance must be based only on information submitted to EPA during the 
rulemaking establishing the effluent limitations guidelines from which 
the variance is being requested, or on information the applicant did 
not have a reasonable opportunity to submit during the rulemaking 
process for these effluent limitations guidelines. FDF variance 
requests must be received by the permitting authority within 180 days 
of publication of the final rule. The specific regulations covering the 
requirements for the administration of FDF variances are found at 40 
CFR 122.21(m)(1), and 40 CFR part 125, subpart D.

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

    Effluent limitations act as a primary mechanism to control the 
discharges of pollutants to waters of the United States. These 
limitations are applied to individual facilities through NPDES permits 
issued by EPA or authorized States under section 402 of the Act.
    The Agency has developed the limitations for this regulation to 
cover the discharge of pollutants for this industrial category. In 
specific cases, the NPDES permitting authority may elect to establish 
technology-based permit limits for pollutants not covered by this 
regulation. In addition, if State water quality standards or other 
provisions of State or Federal Law require limits on pollutants not 
covered by this regulation (or require more stringent limits on covered 
pollutants), the permitting authority must apply those limitations.
    Working in conjunction with the effluent limitations are the 
monitoring conditions set out in a NPDES permit. An integral part of 
the monitoring conditions is the point at which a facility must monitor 
to demonstrate compliance. The point at which a sample is collected can 
have a dramatic effect on the monitoring results for that facility. 
Therefore, it may be necessary to require internal monitoring points in 
order to ensure compliance. Authority to address internal waste streams 
is provided in 40 CFR 122.44(i)(1)(iii) and 122.45(h). Permit writers 
may establish additional internal monitoring points to the extent 
consistent with EPA's regulations.
    An important component of the monitoring requirements established 
by the permitting authority is the frequency at which monitoring is 
required. In costing the various technology options for the oil and gas 
extraction industry, EPA assumed yearly SBF stock limitations 
monitoring for mercury, cadmium, PAH (as phenanthrene), sediment 
toxicity, and biodegradation rates and daily or monthly monitoring for 
diesel oil contamination, formation oil contamination, base fluid 
retained on cuttings, aqueous toxicity, and sediment toxicity. These 
monitoring frequencies may be lower than those generally imposed by 
some permitting authorities, but EPA believes these reduced frequencies 
are appropriate due to the relative costs of monitoring when compared 
to the estimated costs of complying with the promulgated limitations.

E. Analytical Methods

    Section 304(h) of the Clean Water Act directs EPA to promulgate 
guidelines establishing test procedures for the analysis of pollutants. 
These test procedures (methods) are used to determine the presence and 
concentration of pollutants in wastewater, and are used for compliance 
monitoring and for filing applications for the NPDES program under 40 
CFR 122.21, 122.41, 122.44 and 123.25, and for the implementation of 
the pretreatment standards under 40 CFR 403.10 and 403.12. To date, EPA 
has promulgated methods for conventional pollutants, toxic pollutants, 
and for some non-conventional pollutants. The five conventional 
pollutants are defined at 40 CFR 401.16. Table I-B at 40 CFR part 136 
lists the analytical methods approved for these pollutants. The 65 
toxic metals and organic pollutants and classes of pollutants are 
defined at 40 CFR 401.15. From the list of 65 classes of toxic 
pollutants EPA identified a list of 126 ``Priority Pollutants.'' This 
list of Priority Pollutants is shown, for example, at 40 CFR part 423, 
Appendix A. The list includes non-pesticide organic pollutants, metal 
pollutants, cyanide, asbestos, and pesticide pollutants.
    Currently approved methods for metals and cyanide are included in 
the table of approved inorganic test procedures at 40 CFR 136.3, Table 
I-B. Table I-C at 40 CFR 136.3 lists approved methods for measurement 
of non-pesticide organic pollutants, and Table I-D lists approved 
methods for the toxic pesticide pollutants and for other pesticide 
pollutants. Dischargers must use the test methods promulgated at 40 CFR 
136.3 or incorporated by reference in the tables, when available, to 
monitor pollutant discharges from the oil and gas industry, unless 
specified otherwise in part 435 or by the permitting authority.
    As part this rule, EPA is promulgating the use of analytical 
methods for determining additional parameters that are specific to 
characterizing SBFs and other drilling fluids which do not disperse in 
water. These additional stock base fluid parameters include PAH content 
(as phenanthrene), sediment toxicity, and biodegradation rate. 
Additional discharge limitations include prohibition of diesel oil 
discharge, formation (crude) oil contamination, aqueous phase toxicity, 
sediment toxicity, and quantity of drilling fluid discharged with 
cuttings.
    EPA worked with stakeholders to identify methods for determining 
these parameters. For PAH content (as phenanthrene), EPA is 
promulgating the use of EPA Method 1654A. For biodegradation rate, EPA 
is promulgating the use of the anaerobic closed bottle biodegradation 
test (i.e., ISO 11734:1995) as modified for the marine environment 
(i.e., Appendix 4 of subpart A of 40 CFR part 435). For base fluid 
sediment toxicity, EPA is promulgating the use of the American Society 
for Testing and Material (ASTM) Method E-1367-92 supplemented with 
sediment preparation procedures (i.e., Appendix 3 of subpart A of 40 
CFR part 435). For drilling fluid sediment toxicity, EPA is 
promulgating the use of ASTM Method E-1367-92 supplemented with 
sediment preparation procedures (i.e., Appendix 3 of subpart A of 40 
CFR part 435) and reference drilling fluid preparation procedures 
(i.e., Appendix 8 of subpart

[[Page 6894]]

A of 40 CFR part 435). For aqueous toxicity, EPA is promulgating the 
use of the Suspended Particulate Phase (SPP) toxicity test (Appendix 2 
of subpart A of 40 CFR part 435). For formation (crude) oil 
contamination in drilling fluid, EPA is promulgating the use of two 
methods: a reverse phase extraction fluorescence test (RPE) and a gas 
chromatography/mass spectrometry (GC/MS) test. The RPE test (i.e., 
Appendix 6 of subpart A of 40 CFR part 435) is a screening method that 
provides a quick and inexpensive determination of oil contamination for 
use on offshore well drilling sites, while the GC/MS test (i.e., 
Appendix 5 of subpart A of 40 CFR part 435) provides: (1) A definitive 
identification and quantification of oil contamination for baseline 
analysis; and (2) confirmatory results for the RPE when the RPE results 
need confirmation. For determining the quantity of drilling fluid 
discharged with cuttings, EPA is promulgating the use of the American 
Petroleum Institute (API) Retort Method (Recommended Practice 13B-2) 
with sampling procedures (i.e., Appendix 7 of subpart A of 40 CFR part 
435). For determining when Coastal Cook Inlet, Alaska, operators 
qualify for an exemption from the Coastal requirement of zero discharge 
for SBF-cuttings, EPA is promulgating the use of the procedure outlined 
in Appendix 1 of subpart D of 40 CFR part 435.
    EPA Method 1654A, ASTM E-1367-92, and ISO 11734:1995 are 
incorporated by reference into 40 CFR part 435 because they are 
published methods that are widely available to the public. 
Modifications to the anaerobic closed bottle biodegradation test (i.e., 
ISO 11734:1995) are provided in Appendix 4 of subpart A of 40 part 435. 
The SPP toxicity test is given in Appendix 2 of subpart A of 40 part 
435. Supplemental sediment preparation procedures for ASTM E-1367-92 
are provided in Appendix 3 of subpart A of 40 CFR part 435. Reference 
drilling fluid preparation procedures for ASTM E-1367-92 are provided 
in Appendix 8 of subpart A of 40 CFR part 435. The text of the GC/MS 
test, RPE test, and the API retort method are provided in Appendices 5-
7 of subpart A of 40 CFR part 435. The procedure for determining when 
Coastal Cook Inlet operators qualify for an exemption from the Coastal 
requirement of zero discharge for SBF-cuttings is provided in Appendix 
1 of subpart D of 40 CFR part 435.

Appendix A to the Preamble--Abbreviations, Acronyms, and Other 
Terms Used in This Preamble

Act--Clean Water Act
Agency--U.S. Environmental Protection Agency
AOGCC--Alaska Oil and Gas Conservation Commission
API--American Petroleum Institute
ANL--Argonne National Laboratory (DOE)
ASTM--American Society of Testing and Materials
BADCT--The best available demonstrated control technology, for new 
sources under section 306 of the Clean Water Act.
BAT--The best available technology economically achievable, under 
section 304(b)(2)(B) of the Clean Water Act.
bbl--barrel, 42 U.S. gallons
BCT--Best conventional pollutant control technology under section 
304(b)(4)(B).
BMP--Best management practices under section 304(e) of the Clean 
Water Act.
BOD--Biochemical oxygen demand.
BOE--Barrels of oil equivalent
BPJ--Best Professional Judgement
BPT--Best practicable control technology currently available, under 
section 304(b)(1) of the Clean Water Act.
CERCLA--Comprehensive Environmental Response, Compensation, and 
Liability Act
CFR--U.S. Code of Federal Regulations
Clean Water Act--Federal Water Pollution Control Act Amendments of 
1972 as amended (33 U.S.C. 1251 et seq)
Conventional pollutants--Constituents of wastewater as determined by 
section 304(a)(4) of the Act, including, but no limited to, 
pollutants classified as biochemical oxygen demanding, suspended 
solids, oil and grease, fecal coliform, and pH
Direct discharger--A facility which discharges or may discharge 
pollutants to waters of the United States
D&B--Dun & Bradstreet
DOE--U.S. Department of Energy
DWD--Deep-water development model well
DWE--Deep-water exploratory model well
EMO--Enhanced Mineral Oil Drilling Fluid
EPA--U.S. Environmental Protection Agency
FR--Federal Register
GC--Gas Chromatography
GC/FID--Gas Chromatography with Flame Ionization Detection
GC/MS--Gas Chromatography with Mass Spectroscopy Detection
GOM--Gulf of Mexico
Indirect discharger--A facility that introduces wastewater into a 
publicly owned treatment works.
IRFA--Initial Regulatory Flexibility Analysis
LC<INF>50</INF> (or LC50)--The concentration of a test material that 
is lethal to 50% of the test organisms in a bioassay
mg/l--milligrams per liter
MMS--U.S. Department of Interior, Minerals Management Service
NAF--Non-Aqueous Drilling Fluid (includes OBFs, EMOs, and SBFs)
Non-conventional pollutants--Pollutants that have not been 
designated as either conventional pollutants or priority pollutants
NODA--Notice of Data Availability (65 FR 21548; April 21, 2000)
NOIA--National Ocean Industries Association
NOW--Nonhazardous Oilfield Waste
NPDES--National Pollutant Discharge Elimination System
NRDC--Natural Resources Defense Council, Inc.
NSPS--New source performance standards under section 306 of the 
Clean Water Act
NTTAA--National Technology Transfer and Advancement Act
NWQI--Non-Water Quality Environmental Impacts
OBF--Oil-Based Drilling Fluid
OCS--Outer Continental Shelf
OMB--Office of Management and Budget
PAH--Polynuclear Aromatic Hydrocarbon
PDC--Polycrystalline Diamond Compact (drill bit)
POTW--Publicly Owned Treatment Works ppm--parts per million
PPA--Pollution Prevention Act of 1990
Priority pollutants--The 65 pollutants and classes of pollutants 
declared toxic under section 307(a) of the Clean Water Act
PSES--Pretreatment standards for existing sources of indirect 
discharges, under section 307(b) of the Act
PSNS--Pretreatment standards for new sources of indirect discharges, 
under sections 307(b) and (c) of the Act
RFA--Regulatory Flexibility Act
ROC--Retention on Cuttings
RPE--Reverse Phase Extraction
SBA--U.S. Small Business Administration
SBF--Synthetic Based Drilling Fluid
SBF Development Document--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)
SBF Economic Analysis--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)
SBF Environmental Assessment--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)
SBF Statistical Support Document--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)
SBMRC--Synthetic Based Muds Research Consortium
SBREFA--Small Business Regulatory Enforcement Fairness Act
SIC--Standard Industrial Classification
SPP--Suspended Particulate Phase toxicity test (Appendix 2 to 
Subpart A of 40 CFR 435)

[[Page 6895]]

SWD--Shallow-water development model well
SWE--Shallow-water exploratory model well
TSS--Total Suspended Solids
UMRA--Unfunded Mandates Reform Act
UIC--Underground Injection Control programs of the Safe Drinking 
Water Act of 1974 as amended
U.S.C.--United States Code
WBF--Water-Based Drilling Fluid

List of Subjects

40 CFR Part 9

    Reporting and recordkeeping requirements.

40 CFR Part 435

    Environmental protection, Non-aqueous drilling fluids, Oil and gas 
extraction, Pollution prevention, Synthetic based drilling fluids, 
Waste treatment and disposal, Water non-dispersible drilling fluids, 
Water pollution control.

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


    For the reasons set forth in this preamble, 40 CFR parts 9 and 435 
are amended as follows:

PART 9--OMB APPROVALS UNDER THE PAPERWORK REDUCTION ACT

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

    Authority: 7 U.S.C. 135 et seq., 136-136y; 15 U.S.C. 2001, 2003, 
2005, 2006, 2601-2671; 21 U.S.C. 331j, 346a, 348; 31 U.S.C. 9701; 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.


    2. In Sec. 9.1 the table is amended by adding entries in numerical 
order under a new heading titled ``Oil and Gas Extraction Point Source 
Category'' to read as follows:


Sec. 9.1  OMB approvals under the Paperwork Reduction Act.

* * * * *

 
------------------------------------------------------------------------
                                                             OMB control
                      40 CFR citation                            No.
------------------------------------------------------------------------
 
                  *        *        *        *        *
Oil and Gas Extraction Point Source Category:
    435.13.................................................    2040-0230
    435.15.................................................    2040-0230
    435.43.................................................    2040-0230
    435.45.................................................    2040-0230
 
                  *        *        *        *        *
------------------------------------------------------------------------

PART 435--OIL AND GAS EXTRACTION POINT SOURCE CATEGORY

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

    Authority: 33 U.S.C. 1311, 1314, 1316, 1317, 1318, 1342 and 
1361.

Subpart A--Offshore Subcategory

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


Sec. 435.11  Special definitions.

* * * * *
    (b) Average of daily values for 30 consecutive days means the 
average of the daily values obtained during any 30 consecutive day 
period.
    (c) Base fluid means the continuous phase or suspending medium of a 
drilling fluid formulation.
    (d) Base fluid retained on cuttings as applied to BAT effluent 
limitations and NSPS refers to the American Petroleum Institute 
Recommended Practice 13B-2 supplemented with the specifications, 
sampling methods, and averaging method for retention values provided in 
Appendix 7 of Subpart A of this part.
    (e) Biodegradation rate as applied to BAT effluent limitations and 
NSPS for drilling fluids and drill cuttings refers to the ISO 
11734:1995 method: ``Water quality--Evaluation of the `ultimate' 
anaerobic biodegradability of organic compounds in digested sludge--
Method by measurement of the biogas production (1995 edition)'' 
supplemented with modifications in Appendix 4 of 40 CFR part 435, 
subpart A. This incorporation by reference was approved by the Director 
of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR 
part 51. Copies may be obtained from the American National Standards 
Institute, 11 West 42nd Street, 13th Floor, New York, NY 10036. Copies 
may be inspected at the Office of the Federal Register, 800 North 
Capitol Street, NW., Suite 700, Washington, DC. A copy may also be 
inspected at EPA's Water Docket, 401 M Street SW., Washington, DC 
20460.
    (f) Daily values as applied to produced water effluent limitations 
and NSPS means the daily measurements used to assess compliance with 
the maximum for any one day.
    (g) Deck drainage means any waste resulting from deck washings, 
spillage, rainwater, and runoff from gutters and drains including drip 
pans and work areas within facilities subject to this Subpart.
    (h) Development facility means any fixed or mobile structure 
subject to this subpart that is engaged in the drilling of productive 
wells.
    (i) Diesel oil refers to the grade of distillate fuel oil, as 
specified in the American Society for Testing and Materials Standard 
Specification for Diesel Fuel Oils D975-91, that is typically used as 
the continuous phase in conventional oil-based drilling fluids. This 
incorporation by reference was approved by the Director of the Federal 
Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies 
may be obtained from the American Society for Testing and Materials, 
100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies may be 
inspected at the Office of the Federal Register, 800 North Capitol 
Street, NW., Suite 700, Washington, DC. A copy may also be inspected at 
EPA's Water Docket, 401 M Street SW., Washington, DC 20460.
    (j) Domestic waste means materials discharged from sinks, showers, 
laundries, safety showers, eye-wash stations, hand-wash stations, fish 
cleaning stations, and galleys located within facilities subject to 
this Subpart.
    (k) Drill cuttings means the particles generated by drilling into 
subsurface geologic formations and carried out from the wellbore with 
the drilling fluid. Examples of drill cuttings include small pieces of 
rock varying in size and texture from fine silt to gravel. Drill 
cuttings are generally generated from solids control equipment and 
settle out and accumulate in quiescent areas in the solids control 
equipment or other equipment processing drilling fluid (i.e., 
accumulated solids).
    (1) Wet drill cuttings means the unaltered drill cuttings and 
adhering drilling fluid and formation oil carried out from the wellbore 
with the drilling fluid.
    (2) Dry drill cuttings means the residue remaining in the retort 
vessel after completing the retort procedure specified in appendix 7 of 
subpart A of this part.
    (l) Drilling fluid means the circulating fluid (mud) used in the 
rotary drilling of wells to clean and condition the hole and to 
counterbalance formation pressure. Classes of drilling fluids are:
    (1) Water-based drilling fluid means the continuous phase and 
suspending

[[Page 6896]]

medium for solids is a water-miscible fluid, regardless of the presence 
of oil.
    (2) Non-aqueous drilling fluid means the continuous phase and 
suspending medium for solids is a water-immiscible fluid, such as 
oleaginous materials (e.g., mineral oil, enhanced mineral oil, 
paraffinic oil, C<INF>16</INF>-C<INF>18</INF> internal olefins, and 
C<INF>8</INF>-C<INF>16</INF> fatty acid/2-ethylhexyl esters).
    (i) Oil-based means the continuous phase of the drilling fluid 
consists of diesel oil, mineral oil, or some other oil, but contains no 
synthetic material or enhanced mineral oil.
    (ii) Enhanced mineral oil-based means the continuous phase of the 
drilling fluid is enhanced mineral oil.
    (iii) Synthetic-based means the continuous phase of the drilling 
fluid is a synthetic material or a combination of synthetic materials.
    (m) Enhanced mineral oil as applied to enhanced mineral oil-based 
drilling fluid means a petroleum distillate which has been highly 
purified and is distinguished from diesel oil and conventional mineral 
oil in having a lower polycyclic aromatic hydrocarbon (PAH) content. 
Typically, conventional mineral oils have a PAH content on the order of 
0.35 weight percent expressed as phenanthrene, whereas enhanced mineral 
oils typically have a PAH content of 0.001 or lower weight percent PAH 
expressed as phenanthrene.
    (n) Exploratory facility means any fixed or mobile structure 
subject to this Subpart that is engaged in the drilling of wells to 
determine the nature of potential hydrocarbon reservoirs.
    (o) Formation oil means the oil from a producing formation which is 
detected in the drilling fluid, as determined by the GC/MS compliance 
assurance method specified in appendix 5 of subpart A of this part when 
the drilling fluid is analyzed before being shipped offshore, and as 
determined by the RPE method specified in appendix 6 of subpart A of 
this part when the drilling fluid is analyzed at the offshore point of 
discharge. Detection of formation oil by the RPE method may be 
confirmed by the GC/MS compliance assurance method, and the results of 
the GC/MS compliance assurance method shall supercede those of the RPE 
method.
    (p) M9IM means those offshore facilities continuously manned by 
nine (9) or fewer persons or only intermittently manned by any number 
of persons.
    (q) M10 means those offshore facilities continuously manned by ten 
(10) or more persons.
    (r) Maximum as applied to BAT effluent limitations and NSPS for 
drilling fluids and drill cuttings means the maximum concentration 
allowed as measured in any single sample of the barite for 
determination of cadmium and mercury content.
    (s) Maximum for any one day as applied to BPT, BCT and BAT effluent 
limitations and NSPS for oil and grease in produced water means the 
maximum concentration allowed as measured by the average of four grab 
samples collected over a 24-hour period that are analyzed separately. 
Alternatively, for BAT and NSPS the maximum concentration allowed may 
be determined on the basis of physical composition of the four grab 
samples prior to a single analysis.
    (t) Maximum weighted mass ratio averaged over all NAF well sections 
for BAT effluent limitations and NSPS for base fluid retained on 
cuttings means the weighted average base fluid retention for all NAF 
well sections as determined by the API Recommended Practice 13B-2, 
using the methods and averaging calculations presented in Appendix 7 of 
subpart A of this part.
    (u) Method 1654A refers to Method 1654, Revision A, entitled ``PAH 
Content of Oil by HPLC/UV,'' December 1992, which is published in 
Methods for the Determination of Diesel, Mineral, and Crude Oils in 
Offshore Oil and Gas Industry Discharges, EPA-821-R-92-008. This 
incorporation by reference was approved by the Director of the Federal 
Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies 
may be obtained from the National Technical Information Service, 
Springfield, VA 22161, 703-605-6000. Copies may be inspected at the 
Office of the Federal Register, 800 North Capitol Street, NW., Suite 
700, Washington, DC. A copy may also be inspected at EPA's Water 
Docket, 401 M Street SW., Washington, DC 20460.
    (v) Minimum as applied to BAT effluent limitations and NSPS for 
drilling fluids and drill cuttings means the minimum 96-hour 
LC<INF>50</INF> value allowed as measured in any single sample of the 
discharged waste stream. Minimum as applied to BPT and BCT effluent 
limitations and NSPS for sanitary wastes means the minimum 
concentration value allowed as measured in any single sample of the 
discharged waste stream.
    (w)(1) New source means any facility or activity of this 
subcategory that meets the definition of ``new source'' under 40 CFR 
122.2 and meets the criteria for determination of new sources under 40 
CFR 122.29(b) applied consistently with all of the following 
definitions:
    (i) Water area as used in ``site'' in 40 CFR 122.29 and 122.2 means 
the water area and water body floor beneath any exploratory, 
development, or production facility where such facility is conducting 
its exploratory, development or production activities.
    (ii) Significant site preparation work as used in 40 CFR 122.29 
means the process of surveying, clearing or preparing an area of the 
water body floor for the purpose of constructing or placing a 
development or production facility on or over the site.
    (2) ``New Source'' does not include facilities covered by an 
existing NPDES permit immediately prior to the effective date of these 
guidelines pending EPA issuance of a new source NPDES permit.
    (x) No discharge of free oil means that waste streams may not be 
discharged that contain free oil as evidenced by the monitoring method 
specified for that particular stream, e.g., deck drainage or 
miscellaneous discharges cannot be discharged when they would cause a 
film or sheen upon or discoloration of the surface of the receiving 
water; drilling fluids or cuttings may not be discharged when they fail 
the static sheen test defined in Appendix 1 of subpart A of this part.
    (y) Parameters that are regulated in this Subpart and listed with 
approved methods of analysis in Table 1B at 40 CFR 136.3 are defined as 
follows:
    (1) Cadmium means total cadmium.
    (2) Chlorine means total residual chlorine.
    (3) Mercury means total mercury.
    (4) Oil and Grease means total recoverable oil and grease.
    (z) PAH (as phenanthrene) means polynuclear aromatic hydrocarbons 
reported as phenanthrene.
    (aa) Produced sand means the slurried particles used in hydraulic 
fracturing, the accumulated formation sands and scales particles 
generated during production. Produced sand also includes desander 
discharge from the produced water waste stream, and blowdown of the 
water phase from the produced water treating system.
    (bb) Produced water means the water (brine) brought up from the 
hydrocarbon-bearing strata during the extraction of oil and gas, and 
can include formation water, injection water, and any chemicals added 
downhole or during the oil/water separation process.
    (cc) Production facility means any fixed or mobile structure 
subject to this Subpart that is either engaged in well completion or 
used for active recovery of hydrocarbons from producing formations.
    (dd) Sanitary waste means the human body waste discharged from 
toilets and

[[Page 6897]]

urinals located within facilities subject to this Subpart.
    (ee) Sediment toxicity as applied to BAT effluent limitations and 
NSPS for drilling fluids and drill cuttings refers to the ASTM E 1367-
92 method: ``Standard Guide for Conducting 10-day Static Sediment 
Toxicity Tests with Marine and Estuarine Amphipods,'' 1992, with 
Leptocheirus plumulosus as the test organism and sediment preparation 
procedures specified in Appendix 3 of 40 CFR part 435, subpart A. This 
incorporation by reference was approved by the Director of the Federal 
Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies 
may be obtained from the American Society for Testing and Materials, 
100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies may be 
inspected at the Office of the Federal Register, 800 North Capitol 
Street, NW., Suite 700, Washington, DC. A copy may also be inspected at 
EPA's Water Docket, 401 M Street SW., Washington, DC 20460.
    (ff) Solids control equipment means shale shakers, centrifuges, mud 
cleaners, and other equipment used to separate drill cuttings and/or 
stock barite solids from drilling fluid recovered from the wellbore.
    (gg) SPP toxicity as applied to BAT effluent limitations and NSPS 
for drilling fluids and drill cuttings refers to the bioassay test 
procedure presented in Appendix 2 of subpart A of this part.
    (hh) Static sheen test means the standard test procedure that has 
been developed for this industrial subcategory for the purpose of 
demonstrating compliance with the requirement of no discharge of free 
oil. The methodology for performing the static sheen test is presented 
in Appendix 1 of subpart A of this part.
    (ii) Stock barite means the barite that was used to formulate a 
drilling fluid.
    (jj) Stock base fluid means the base fluid that was used to 
formulate a drilling fluid.
    (kk) Synthetic material as applied to synthetic-based drilling 
fluid means material produced by the reaction of specific purified 
chemical feedstock, as opposed to the traditional base fluids such as 
diesel and mineral oil which are derived from crude oil solely through 
physical separation processes. Physical separation processes include 
fractionation and distillation and/or minor chemical reactions such as 
cracking and hydro processing. Since they are synthesized by the 
reaction of purified compounds, synthetic materials suitable for use in 
drilling fluids are typically free of polycyclic aromatic hydrocarbons 
(PAH's) but are sometimes found to contain levels of PAH up to 0.001 
weight percent PAH expressed as phenanthrene. Internal olefins and 
vegetable esters are two examples of synthetic materials suitable for 
use by the oil and gas extraction industry in formulating drilling 
fluids. Internal olefins are synthesized from the isomerization of 
purified straight-chain (linear) hydrocarbons such as C<INF>16</INF>-
C<INF>18</INF> linear alpha olefins. C<INF>16</INF>-C<INF>18</INF> 
linear alpha olefins are unsaturated hydrocarbons with the carbon to 
carbon double bond in the terminal position. Internal olefins are 
typically formed from heating linear alpha olefins with a catalyst. The 
feed material for synthetic linear alpha olefins is typically purified 
ethylene. Vegetable esters are synthesized from the acid-catalyzed 
esterification of vegetable fatty acids with various alcohols. EPA 
listed these two branches of synthetic fluid base materials to provide 
examples, and EPA does not mean to exclude other synthetic materials 
that are either in current use or may be used in the future. A 
synthetic-based drilling fluid may include a combination of synthetic 
materials.
    (ll) Well completion fluids means salt solutions, weighted brines, 
polymers, and various additives used to prevent damage to the well bore 
during operations which prepare the drilled well for hydrocarbon 
production.
    (mm) Well treatment fluids means any fluid used to restore or 
improve productivity by chemically or physically altering hydrocarbon-
bearing strata after a well has been drilled.
    (nn) Workover fluids means salt solutions, weighted brines, 
polymers, or other specialty additives used in a producing well to 
allow for maintenance, repair or abandonment procedures.
    (oo) 4-day LC<INF>50</INF> as applied to the sediment toxicity BAT 
effluent limitations and NSPS means the concentration (milligrams/
kilogram dry sediment) of the drilling fluid in sediment that is lethal 
to 50 percent of the Leptocheirus plumulosus test organisms exposed to 
that concentration of the drilling fluids after four days of constant 
exposure.
    (pp) 10-day LC<INF>50</INF> as applied to the sediment toxicity BAT 
effluent limitations and NSPS means the concentration (milligrams/
kilogram dry sediment) of the base fluid in sediment that is lethal to 
50 percent of the Leptocheirus plumulosus test organisms exposed to 
that concentration of the base fluids after ten days of constant 
exposure.
    (qq) 96-hour LC<INF>50</INF> means the concentration (parts per 
million) or percent of the suspended particulate phase (SPP) from a 
sample that is lethal to 50 percent of the test organisms exposed to 
that concentration of the SPP after 96 hours of constant exposure.
    (rr) C<INF>16</INF>-C<INF>18</INF> internal olefin means a 65/35 
blend, proportioned by mass, of hexadecene and octadecene, 
respectively. Hexadecene is an unsaturated hydrocarbon with a carbon 
chain length of 16, an internal double carbon bond, and is represented 
by the Chemical Abstracts Service (CAS) No. 26952-14-7. Octadecene is 
an unsaturated hydrocarbon with a carbon chain length of 18, an 
internal double carbon bond, and is represented by the Chemical 
Abstracts Service (CAS) No. 27070-58-2. (Properties available from the 
Chemical Abstracts Service, 2540 Olentangy River Road, PO Box 3012, 
Columbus, OH, 43210).
    (ss) C<INF>16</INF>-C<INF>18</INF> internal olefin drilling fluid 
means a C<INF>16</INF>-C<INF>18</INF> internal olefin drilling fluid 
formulated as specified in Appendix 8 of subpart A of this part.
    (tt) C<INF>12</INF>-C<INF>14</INF> ester and C<INF>8</INF> ester 
means the fatty acid/2-ethylhexyl esters with carbon chain lengths 
ranging from 8 to 16 and represented by the Chemical Abstracts Service 
(CAS) No. 135800-37-2. (Properties available from the Chemical 
Abstracts Service, 2540 Olentangy River Road, PO Box 3012, Columbus, 
OH, 43210)

    3. In Sec. 435.12 the table is amended by removing the entries 
``Drilling muds'' and ``Drill cuttings'' and by adding new entries 
(after ``Deck drainage'') for ``Water based'' and ``Non-aqueous'' to 
read as follows:


Sec. 435.12  Effluent limitations guidelines representing the degree of 
effluent reduction attainable by the application of the best 
practicable control technology currently available (BPT).

* * * * *

[[Page 6898]]



                                    BPT Effluent Limitations--Oil and Grease
                                            [In milligrams per liter]
----------------------------------------------------------------------------------------------------------------
                                                                 Average of values for 30
   Pollutant parameter waste source      Maximum for any 1 day    consecutive days shall     Residual chlorine
                                                                        not exceed         minimum for any 1 day
----------------------------------------------------------------------------------------------------------------
 
*                  *                  *                  *                  *                  *
                                                        *
Water-based:
    Drilling fluids..................  (\1\)...................  (\1\)...................  NA
    Drill Cuttings...................  (\1\)...................  (\1\)...................  NA
Non-aqueous:
    Drilling fluids..................  No discharge............  No discharge............  NA
    Drill Cuttings...................  (\1\)...................  (\1\)...................  NA
 
*                  *                  *                  *                  *                  *
                                                       *
----------------------------------------------------------------------------------------------------------------
\1\ No discharge of free oil.

* * * * *

    4. In Sec. 435.13 the table is amended by revising entry (B) under 
``Drilling fluids and drill cuttings'' and by revising footnote 2 and 
adding footnotes 5-11 to read as follows:


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

* * * * *

                        Bat Effluent Limitations
------------------------------------------------------------------------
                                    Pollutant           BAT effluent
         Waste source               parameter            limitation
------------------------------------------------------------------------
 
*                  *                  *                  *
                  *                  *                  *
Drilling fluids and drill
 cuttings:
 
*                  *                  *                  *
                  *                  *                  *
(B) For facilities located
 beyond 3 miles from shore:
    Water-based drilling        SPP Toxicity.....  Minimum 96-hour LC<INF>50</INF>
     fluids and associated                          of the SPP Toxicity
     drill cuttings.                                Test \2\ shall be 3%
                                                    by volume.
                                Free oil.........  No discharge.\3\
                                Diesel oil.......  No discharge.
                                Mercury..........  1 mg/kg dry weight
                                                    maximum in the stock
                                                    barite.
                                Cadmium..........  3 mg/kg dry weight
                                                    maximum in the stock
                                                    barite.
    Non-aqueous drilling        .................  No discharge.
     fluids (NAFs).
Drill cuttings associated with
 non-aqueous drilling fluids:
    Stock Limitations (C<INF>16</INF>-C<INF>18</INF>  Mercury..........  1 mg/kg dry weight
     internal olefin).                              maximum in the stock
                                                    barite.
                                Cadmium..........  3 mg/kg dry weight
                                                    maximum in the stock
                                                    barite.
                                Polynuclear        PAH mass ratio \5\
                                 Aromatic           shall not exceed
                                 Hydrocarbons       1x10<SUP>-5</SUP>.
                                 (PAH).
                                Sediment toxicity  Base fluid sediment
                                                    toxicity ratio \6\
                                                    shall not exceed
                                                    1.0.
                                Biodegradation     Biodegradation rate
                                 rate.              ratio \7\ shall not
                                                    exceed 1.0.
    Discharge Limitations.....  Diesel oil.......  No discharge.
                                SPP Toxicity.....  Minimum 96-hour LC<INF>50</INF>
                                                    of the SPP Toxicity
                                                    Test \2\ shall be 3%
                                                    by volume.
                                Sediment toxicity  Drilling fluid
                                                    sediment toxicity
                                                    ratio \8\ shall not
                                                    exceed 1.0.
                                Formation Oil....  No discharge.\9\
                                Base fluid         For NAFs that meet
                                 retained on        the stock
                                 cuttings.          limitations (C<INF>16</INF>-C<INF>18</INF>
                                                    internal olefin) in
                                                    this table, the
                                                    maximum weighted
                                                    mass ratio averaged
                                                    over all NAF well
                                                    sections shall be
                                                    6.9 g-NAF base fluid/
                                                    100 g-wet drill
                                                    cuttings.\10\
                                                   For NAFs that meet
                                                    the C<INF>12</INF>-C<INF>14</INF> ester or
                                                    C<INF>8</INF> ester stock
                                                    limitations in
                                                    footnote 11 of this
                                                    table, the maximum
                                                    weighted mass ratio
                                                    averaged over all
                                                    NAF well sections
                                                    shall be 9.4 g-NAF
                                                    base fluid/100 g-wet
                                                    drill cuttings.
 

[[Page 6899]]

 
*                  *                  *                  *
                    *                  *              *
------------------------------------------------------------------------
*                  *                  *                  *
     *                  *              *
\2\ As determined by the suspended particulate phase (SPP) toxicity test
  (Appendix 2 of subpart A of this part).
\3\ As determined by the static sheen test (Appendix 1 of subpart A of
  this part).
*                  *                  *                  *
     *                  *              *
\5\ PAH mass ratio = Mass (g) of PAH (as phenanthrene)/Mass (g) of stock
  base fluid as determined by EPA Method 1654, Revision A, (specified at
  Sec.  435.11(u)) entitled ``PAH Content of Oil by HPLC/UV,'' December
  1992, which is published in Methods for the Determination of Diesel,
  Mineral, and Crude Oils in Offshore Oil and Gas Industry Discharges,
  EPA-821-R-92-008. This incorporation by reference was approved by the
  Director of the Federal Register in accordance with 5 U.S.C. 552(a)
  and 1 CFR part 51. Copies may be obtained from the National Technical
  Information Service, Springfield, VA 22161, 703-605-6000. Copies may
  be inspected at the Office of the Federal Register, 800 North Capitol
  Street, NW., Suite 700, Washington, DC. A copy may also be inspected
  at EPA's Water Docket, 401 M Street SW., Washington, DC 20460.
\6\ Base fluid sediment toxicity ratio = 10-day LC<INF>50</INF> of C<INF>16</INF>-C<INF>18</INF> internal
  olefin/10-day LC<INF>50</INF> of stock base fluid as determined by ASTM E 1367-92
  [specified at Sec.  435.11(ee)] method: ``Standard Guide for
  Conducting 10-day Static Sediment Toxicity Tests with Marine and
  Estuarine Amphipods,'' 1992, after preparing the sediment according to
  the method specified in Appendix 3 of subpart A of this part. This
  incorporation by reference was approved by the Director of the Federal
  Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies
  may be obtained from the American Society for Testing and Materials,
  100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies may be
  inspected at the Office of the Federal Register, 800 North Capitol
  Street, NW., Suite 700, Washington, DC. A copy may also be inspected
  at EPA's Water Docket, 401 M Street SW., Washington, DC 20460.
\7\ Biodegradation rate ratio = Cumulative gas production (ml) of C<INF>16</INF>-
  C<INF>18</INF> internal olefin/Cumulative gas production (ml) of stock base
  fluid, both at 275 days as determined by ISO 11734:1995 [specified at
  Sec.  435.11(e)] method: ``Water quality--Evaluation of the `ultimate'
  anaerobic biodegradability of organic compounds in digested sludge--
  Method by measurement of the biogas production (1995 edition)'' as
  modified for the marine environment (Appendix 4 of subpart A of this
  part). This incorporation by reference was approved by the Director of
  the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part
  51. Copies may be obtained from the American National Standards
  Institute, 11 West 42nd Street, 13th Floor, New York, NY 10036. Copies
  may be inspected at the Office of the Federal Register, 800 North
  Capitol Street, NW., Suite 700, Washington, DC. A copy may also be
  inspected at EPA's Water Docket, 401 M Street SW., Washington, DC
  20460.
\8\ Drilling fluid sediment toxicity ratio = 4-day LC<INF>50</INF> of C<INF>16</INF>-C<INF>18</INF>
  internal olefin drilling fluid/4-day LC<INF>50</INF> of drilling fluid removed
  from drill cuttings at the solids control equipment as determined by
  ASTM E 1367-92 (specified at Sec.  435.11(ee)) method: ``Standard
  Guide for Conducting 10-day Static Sediment Toxicity Tests with Marine
  and Estuarine Amphipods,'' 1992, after preparing the sediment
  according to the method specified in Appendix 3 of subpart A of this
  part. This incorporation by reference was approved by the Director of
  the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part
  51. Copies may be obtained from the American Society for Testing and
  Materials, 100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies
  may be inspected at the Office of the Federal Register, 800 North
  Capitol Street, NW., Suite 700, Washington, DC. A copy may also be
  inspected at EPA's Water Docket, 401 M Street SW., Washington, DC
  20460.
\9\ As determined before drilling fluids are shipped offshore by the GC/
  MS compliance assurance method (Appendix 5 of subpart A of this part),
  and as determined prior to discharge by the RPE method (Appendix 6 of
  subpart A of this part) applied to drilling fluid removed from drill
  cuttings. If the operator wishes to confirm the results of the RPE
  method (Appendix 6 of subpart A of this part), the operator may use
  the GC/MS compliance assurance method (Appendix 5 of subpart A of this
  part). Results from the GC/MS compliance assurance method (Appendix 5
  of subpart A of this part) shall supercede the results of the RPE
  method (Appendix 6 of subpart A of this part).
\10\ Maximum permissible retention of non-aqueous drilling fluid (NAF)
  base fluid on wet drill cuttings averaged over drilling intervals
  using NAFs as determined by the API retort method (Appendix 7 of
  subpart A of this part). This limitation is applicable for NAF base
  fluids that meet the base fluid sediment toxicity ratio (Footnote 6),
  biodegradation rate ratio (Footnote 7), PAH, mercury, and cadmium
  stock limitations (C<INF>16</INF>-C<INF>18</INF> internal olefin) defined above in this
  table.
\11\ Maximum permissible retention of non-aqueous drilling fluid (NAF)
  base fluid on wet drill cuttings average over drilling intervals using
  NAFs as determined by the API retort method (Appendix 7 of subpart A
  of this part). This limitation is applicable for NAF base fluids that
  meet the ester base fluid sediment toxicity ratio and ester
  biodegradation rate ratio stock limitations defined as: (a) ester base
  fluid sediment toxicity ratio = 10-day LC<INF>50</INF> of C<INF>12</INF>-C<INF>14</INF> ester or C<INF>8</INF>
  ester /10-day LC<INF>50</INF> of stock base fluid as determined by ASTM E 1367-92
  (specified at Sec.  435.11(ee)) method: ``Standard Guide for
  Conducting 10-day Static Sediment Toxicity Tests with Marine and
  Estuarine Amphipods,'' 1992, after preparing the sediment according to
  the method specified in Appendix 3 of subpart A of this part. This
  incorporation by reference was approved by the Director of the Federal
  Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies
  may be obtained from the American Society for Testing and Materials,
  100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies may be
  inspected at the Office of the Federal Register, 800 North Capitol
  Street, NW., Suite 700, Washington, DC. A copy may also be inspected
  at EPA's Water Docket, 401 M Street SW., Washington, DC 20460. (b)
  ester biodegradation rate ratio = Cumulative gas production (ml) of
  C<INF>12</INF>-C<INF>14</INF> ester or C<INF>8</INF> ester/Cumulative gas production (ml) of stock base
  fluid, both at 275 days as determined by ISO 11734:1995 (specified at
  Sec.  435.11(e)) method: ``Water quality--Evaluation of the `ultimate'
  anaerobic biodegradability of organic compounds in digested sludge--
  Method by measurement of the biogas production (1995 edition)'' as
  modified for the marine environment (Appendix 4 of subpart A of this
  part). This incorporation by reference was approved by the Director of
  the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part
  51. Copies may be obtained from the American National Standards
  Institute, 11 West 42nd Street, 13th Floor, New York, NY 10036. Copies
  may be inspected at the Office of the Federal Register, 800 North
  Capitol Street, NW., Suite 700, Washington, DC. A copy may also be
  inspected at EPA's Water Docket, 401 M Street SW., Washington, DC
  20460. (c) PAH mass ratio (Footnote 5), mercury, and cadmium stock
  limitations (C<INF>16</INF>-C<INF>18</INF> internal olefin) defined above in this table.


    5. In Sec. 435.14 the table is amended by revising entry (B) under 
``Drilling fluids and drill cuttings'' to read as follows:


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

* * * * *

                        BCT Effluent Limitations
------------------------------------------------------------------------
                                  Pollutant
         Waste source             parameter      BCT effluent limitation
------------------------------------------------------------------------
 
*                  *                  *                  *
                  *                  *                  *
Drilling fluids and drill
 cuttings:
 

[[Page 6900]]

 
*                  *                  *                  *
                  *                  *                  *
(B) For facilities located
 beyond 3 miles from shore:
    Water-based drilling       Free Oil.......  No discharge.\2\
     fluids and associated
     drill cuttings.
    Non-aqueous drilling       ...............  No discharge.
     fluids.
    Drill cuttings associated  Free Oil.......  No discharge.\2\
     with non-aqueous
     drilling fluids.
------------------------------------------------------------------------
*                  *                  *                  *
     *                  *              *
\2\ As determined by the static sheen test (Appendix 1 of Subpart A of
  this part).
*                  *                  *                  *
     *                  *                  *


    6. In Sec. 435.15 the table is amended by revising entry (B) under 
``Drilling fluids and drill cuttings'' and by revising footnote 2 and 
adding footnotes 5-11 to read as follows:


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

* * * * *

                 New Source Performance Standards (NSPS)
------------------------------------------------------------------------
                                    Pollutant
         Waste source               parameter               NSPS
------------------------------------------------------------------------
 
*                  *                  *                  *
                  *                  *                  *
Drilling fluids and drill
 cuttings:
 
*                  *                  *                  *
                  *                  *                  *
(B) For facilities located
 beyond 3 miles from shore:
    Water-based drilling        SPP Toxicity.....  Minimum 96-hour LC<INF>50</INF>
     fluids and associated                          of the SPP Toxicity
     drill cuttings.                                Test <SUP>2</SUP> shall be 3%
                                                    by volume.
                                Free oil.........  No discharge.<SUP>3</SUP>
                                Diesel oil.......  No charge.
                                Mercury..........  1mg/kg dry weight
                                                    maximum in the stock
                                                    barite.
                                Cadmium..........  3 mg/kg dry weight
                                                    maximum in the stock
                                                    barite.
    Non-aqueous drilling        .................  No charge.
     fluids.
Drill cuttings associated with
 non-aqueous drilling fluids:
    Stock Limitations (C<INF>16</INF>-C<INF>18</INF>  Mercury..........  1mg/kg dry weight
     internal olefin.                               maximum in the stock
                                                    barite.
                                Cadmium..........  3 mg/kg dry weight
                                                    maximum in the stock
                                                    barite.
                                Polynuclear        PAH mass ratio<SUP>5</SUP> shall
                                 Aromatic           not exceed 1 x 10<SUP>-5</SUP>
                                 Hydrocarbons
                                 (PAH).
                                Sediment toxicity  Base fluid sediment
                                                    toxicity ratio <SUP>6</SUP>
                                                    shall not exceed
                                                    1.0.
                                Biodegradation     Biodegradation rate
                                 rate.              ratio<SUP>7</SUP> shall not
                                                    exceed 1.0.
    Discharge Limitations.....  Diesel oil.......  No discharge.
                                SPP Toxicity.....  Minimum 96-hour LC<INF>50</INF>
                                                    of the SPP Toxicity
                                                    Test <SUP>2</SUP> shall be 3%
                                                    by volume.
                                Sediment toxicity  Drilling fluid
                                                    sediment toxicity
                                                    ratio <SUP>8</SUP> shall not
                                                    exceed 1.0.
                                Formation Oil....  No discharge.<SUP>9</SUP>
                                Base fluid         For NAFs that meet
                                 retained on        the stock
                                 cuttings.          limitations (C<INF>16</INF>-C<INF>18</INF>
                                                    internal olefin) in
                                                    this table, the
                                                    maximum weighted
                                                    mass ratio averaged
                                                    over all NAF well
                                                    sections shall be
                                                    6.9 g-NAF base fluid/
                                                    100 g-wet drill
                                                    cuttings.<SUP>10</SUP>
                                                   For NAFs that meet
                                                    the C<INF>12</INF>-C<INF>14</INF> ester or
                                                    C<INF>8</INF> ester stock
                                                    limitations in
                                                    footnote 11 of this
                                                    table, the maximum
                                                    weighted mass ratio
                                                    averaged over all
                                                    NAF well sections
                                                    shall be 9.4 g-NAF
                                                    base fluid/100 g-wet
                                                    drill cuttings.
 
*                  *                  *                *
                 *                  *                  *
------------------------------------------------------------------------
*                  *                  *                *
   *                  *              *
\2\ As determined by the suspended particulate phase (SPP) toxicity test
  (Appendix 2 of subpart A of this part).
\3\ As determined by the static sheen test (appendix 1 of subpart A of
  this part).
*                  *                  *                *
   *                  *                *
\5\ PAH mass ratio = Mass (g) of PAH (as phenanthrene)/Mass (g) of stock
  base fluid as determined by EPA Method 1654, Revision A, (specified at
  Sec.  435.11(u)) entitled ``PAH Content of Oil by HPLC/UV,'' December
  1992, which is published in Methods for the Determination of Diesel,
  Mineral, and Crude Oils in Offshore Oil and Gas Industry Discharges,
  EPA-821-R-92-008. This incorporation by reference was approved by the
  Director of the Federal Register in accordance with 5 U.S.C. 552(a)
  and 1 CFR part 51. Copies may be obtained from the National Technical
  Information Service, Springfield, VA 22161, 703-605-6000. Copies may
  be inspected at the Office of the Federal Register, 800 North Capitol
  Street, NW., Suite 700, Washington, DC. A copy may also be inspected
  at EPA's Water Docket, 401 M Street SW., Washington, DC 20460.

[[Page 6901]]

 
\6\ Base fluid sediment toxicity ratio = 10-day LC<INF>50</INF> of C<INF>16</INF>-C<INF>18</INF> internal
  olefin/10-day LC<INF>50</INF> of stock base fluid as determined by ASTM E 1367-92
  (specified at Sec.  435.11(ee)) method: ``Standard Guide for
  Conducting 10-day Static Sediment Toxicity Tests with Marine and
  Estuarine Amphipods,'' 1992, after preparing the sediment according to
  the method specified in Appendix 3 of subpart A of this part. This
  incorporation by reference was approved by the Director of the Federal
  Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies
  may be obtained from the American Society for Testing and Materials,
  100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies may be
  inspected at the Office of the Federal Register, 800 North Capitol
  Street, NW., Suite 700, Washington, DC. A copy may also be inspected
  at EPA's Water Docket, 401 M Street SW., Washington, DC 20460.
\7\ Biodegradation rate ratio = Cumulative gas production (ml) of C<INF>16</INF>-
  C<INF>18</INF> internal olefin/Cumulative gas production (ml) of stock base
  fluid, both at 275 days as determined by ISO 11734:1995 (specified at
  Sec.  435.11(e)) method: ``Water quality--Evaluation of the `ultimate'
  anaerobic biodegradability of organic compounds in digested sludge--
  Method by measurement of the biogas production (1995 edition)'' as
  modified for the marine environment (Appendix 4 of subpart A of this
  part). This incorporation by reference was approved by the Director of
  the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part
  51. Copies may be obtained from the American National Standards
  Institute, 11 West 42nd Street, 13th Floor, New York, NY 10036. Copies
  may be inspected at the Office of the Federal Register, 800 North
  Capitol Street, NW., Suite 700, Washington, DC. A copy may also be
  inspected at EPA's Water Docket, 401 M Street SW., Washington, DC
  20460.
\8\ Drilling fluid sediment toxicity ratio = 4-day LC<INF>50</INF> of C<INF>16</INF>-C<INF>18</INF>
  internal olefin drilling fluid/4-day LC<INF>50</INF> of drilling fluid removed
  from drill cuttings at the solids control equipment as determined by
  ASTM E 1367-92 (specified at Sec.  435.11(ee)) method: ``Standard
  Guide for Conducting 10-day Static Sediment Toxicity Tests with Marine
  and Estuarine Amphipods,'' 1992, after preparing the sediment
  according to the method specified in Appendix 3 of subpart A of this
  part. This incorporation by reference was approved by the Director of
  the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part
  51. Copies may be obtained from the American Society for Testing and
  Materials, 100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies
  may be inspected at the Office of the Federal Register, 800 North
  Capitol Street, NW., Suite 700, Washington, DC. A copy may also be
  inspected at EPA's Water Docket, 401 M Street SW., Washington, DC
  20460.
\9\ As determined before drilling fluids are shipped offshore by the GC/
  MS compliance assurance method (Appendix 5 of subpart A of this part),
  and as determined prior to discharge by the RPE method (Appendix 6 of
  subpart A of this part) applied to drilling fluid removed from drill
  cuttings. If the operator wishes to confirm the results of the RPE
  method (Appendix 6 of subpart A of this part), the operator may use
  the GC/MS compliance assurance method (Appendix 5 of subpart A of this
  part). Results from the GC/MS compliance assurance method (Appendix 5
  of subpart A of this part) shall supercede the results of the RPE
  method (Appendix 6 of subpart A of this part).
\10\ Maximum permissible retention of non-aqueous drilling fluid (NAF)
  base fluid on wet drill cuttings averaged over drilling intervals
  using NAFs as determined by the API retort method (Appendix 7 of
  subpart A of this part). This limitation is applicable for NAF base
  fluids that meet the base fluid sediment toxicity ratio (Footnote 6),
  biodegradation rate ratio (Footnote 7), PAH, mercury, and cadmium
  stock limitations (C<INF>16</INF>-C<INF>18</INF> internal olefin) defined above in this
  table.
\11\ Maximum permissible retention of non-aqueous drilling fluid (NAF)
  base fluid on wet drill cuttings average over drilling intervals using
  NAFs as determined by the API retort method (Appendix 7 of subpart A
  of this part). This limitation is applicable for NAF base fluids that
  meet the ester base fluid sediment toxicity ratio and ester
  biodegradation rate ratio stock limitations defined as: (a) Ester base
  fluid sediment toxicity ratio = 10-day LC<INF>50</INF> of C<INF>12</INF>-C<INF>14</INF> ester or C<INF>8</INF>
  ester /10-day LC<INF>50</INF> of stock base fluid as determined by ASTM E 1367-92
  [specified at Sec.  435.11(ee)] method: ``Standard Guide for
  Conducting 10-day Static Sediment Toxicity Tests with Marine and
  Estuarine Amphipods,'' 1992, after preparing the sediment according to
  the method specified in Appendix 3 of subpart A of this part. This
  incorporation by reference was approved by the Director of the Federal
  Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies
  may be obtained from the American Society for Testing and Materials,
  100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies may be
  inspected at the Office of the Federal Register, 800 North Capitol
  Street, NW., Suite 700, Washington, DC. A copy may also be inspected
  at EPA's Water Docket, 401 M Street SW., Washington, DC 20460; (b)
  Ester biodegradation rate ratio = Cumulative gas production (ml) of
  C<INF>12</INF>-C<INF>14</INF> ester or C<INF>8</INF> ester/Cumulative gas production (ml) of stock base
  fluid, both at 275 days as determined by ISO 11734:1995 (specified at
  Sec.  435.11(e)) method: ``Water quality--Evaluation of the `ultimate'
  anaerobic biodegradability of organic compounds in digested sludge--
  Method by measurement of the biogas production (1995 edition)'' as
  modified for the marine environment (Appendix 4 of subpart A of this
  part). This incorporation by reference was approved by the Director of
  the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part
  51. Copies may be obtained from the American National Standards
  Institute, 11 West 42nd Street, 13th Floor, New York, NY 10036. Copies
  may be inspected at the Office of the Federal Register, 800 North
  Capitol Street, NW., Suite 700, Washington, DC. A copy may also be
  inspected at EPA's Water Docket, 401 M Street SW., Washington, DC
  20460; and (c) PAH mass ratio (Footnote 5), mercury, and cadmium stock
  limitations (C<INF>16</INF>-C<INF>18</INF> internal olefin) defined above in this table.


    7. Subpart A of this part is amended by adding Appendices 3 through 
8 as follows:

Appendix 3 to Subpart A of Part 435--Procedure for Mixing Base Fluids 
with Sediments

    This procedure describes a method for amending uncontaminated 
and nontoxic (control) sediments with the base fluids that are used 
to formulate synthetic-based drilling fluids and other non-aqueous 
drilling fluids. Initially, control sediments shall be press-sieved 
through a 2000 micron mesh sieve to remove large debris. Then press-
sieve the sediment through a 500 micron sieve to remove indigenous 
organisms that may prey on the test species or otherwise confound 
test results. Homogenize control sediment to limit the effects of 
settling that may have occurred during storage. Sediments should be 
homogenized before density determinations and addition of base fluid 
to control sediment. Because base fluids are strongly hydrophobic 
and do not readily mix with sediment, care must be taken to ensure 
base fluids are thoroughly homogenized within the sediment. All 
concentrations are weight-to-weight (mg of base fluid to kg of dry 
control sediment). Sediment and base fluid mixing shall be 
accomplished by using the following method.
    1. Determine the wet to dry ratio for the control sediment by 
weighing approximately 10 g subsamples of the screened and 
homogenized wet sediment into tared aluminum weigh pans. Dry 
sediment at 105  deg.C for 18-24 h. Remove sediment and cool in a 
desiccator until a constant weight is achieved. Re-weigh the samples 
to determine the dry weight. Determine the wet/dry ratio by dividing 
the net wet weight by the net dry weight:

[Wet Sediment Weight (g)]/[Dry Sediment Weight (g)] = Wet to Dry 
Ratio  [1]

    2. Determine the density (g/mL) of the wet control or dilution 
sediment. This shall be used to determine total volume of wet 
sediment needed for the various test treatments.

[Mean Wet Sediment Weight (g)]/[Mean Wet Sediment Volume (mL)] = Wet 
Sediment Density (g/mL)  [2]

    3. To determine the amount of base fluid needed to obtain a test 
concentration of 500 mg base fluid per kg dry sediment use the 
following formulas:
    Determine the amount of wet sediment required:

[Wet Sediment Density (g/mL)]  x  [Volume of Sediment Required per 
Concentration (mL)] = Weight Wet Sediment Required per Conc. (g)  
[3]

    Determine the amount of dry sediment in kilograms (kg) required 
for each concentration:

{[Wet Sediment per Concentration (g)]/[Mean Wet to Dry Ratio]}  x  
(1kg/1000g) = Dry Weight Sediment (kg)  [4]

    Finally, determine the amount of base fluid required to spike 
the control sediment at each concentration:

[Conc. Desired (mg/kg)]  x  [Dry Weight Sediment (kg)] = Base Fluid 
Required (mg)  [5]

    For spiking test substances other than pure base fluids (e.g., 
whole mud formulations), determine the spike amount as follows:

[Conc. Desired (mL/kg)]  x  [Dry Weight Sediment (kg)]  x  [Test 
Substance Density (g/mL)] = Test Substance Required (g)  [6]

    4. For primary mixing, place appropriate amounts of weighed base 
fluid into stainless mixing bowls, tare the vessel weight, then add 
sediment and mix with a high-shear dispersing impeller for 9 
minutes. The concentration of base fluid in sediment from this mix, 
rather than the nominal concentration, shall be used in calculating 
LC<INF>50</INF> values.
    5. Tests for homogeneity of base fluid in sediment are to be 
performed during the procedure development phase. Because of

[[Page 6902]]

difficulty of homogeneously mixing base fluid with sediment, it is 
important to demonstrate that the base fluid is evenly mixed with 
sediment. The sediment shall be analyzed for total petroleum 
hydrocarbons (TPH) using EPA Methods 3550A and 8015M, with samples 
taken both prior to and after distribution to replicate test 
containers. Base-fluid content is measured as TPH. After mixing the 
sediment, a minimum of three replicate sediment samples shall be 
taken prior to distribution into test containers. After the test 
sediment is distributed to test containers, an additional three 
sediment samples shall be taken from three test containers to ensure 
proper distribution of base fluid within test containers. Base-fluid 
content results shall be reported within 48 hours of mixing. The 
coefficient of variation (CV) for the replicate samples must be less 
than 20%. If base-fluid content results are not within the 20% CV 
limit, the test sediment shall be remixed. Tests shall not begin 
until the CV is determined to be below the maximum limit of 20%. 
During the test, a minimum of three replicate containers shall be 
sampled to determine base-fluid content during each sampling period.
    6. Mix enough sediment in this way to allow for its use in the 
preparation of all test concentrations and as a negative control. 
When commencing the sediment toxicity test, range-finding tests may 
be required to determine the concentrations that produce a toxic 
effect if these data are otherwise unavailable. The definitive test 
shall bracket the LC<INF>50</INF>, which is the desired endpoint. 
The results for the base fluids shall be reported in mg of base 
fluid per kg of dry sediment.

References

    American Society for Testing and Materials (ASTM). 1996. 
Standard Guide for Collection, Storage, Characterization, and 
Manipulation of Sediments for Toxicological Testing. ASTM E 1391-94. 
Annual Book of ASTM Standards, Volume 11.05, pp. 805-825.
    Ditsworth, G.R., D.W. Schults and J.K.P. Jones. 1990. 
Preparation of benthic substrates for sediment toxicity testing, 
Environ. Toxicol. Chem. 9:1523-1529.
    Suedel, B.C., J.H. Rodgers, Jr. and P.A. Clifford. 1993. 
Bioavailability of fluoranthene in freshwater sediment toxicity 
tests. Environ. Toxicol. Chem. 12:155-165.
    U.S. EPA. 1994. Methods for Assessing the Toxicity of Sediment-
associated Contaminants with Estuarine and Marine Amphipods. EPA/
600/R-94/025. Office of Research and Development, Washington, DC.

Appendix 4 to Subpart A of Part 435--Determination of Biodegradation of 
Synthetic Base Fluids in a Marine Closed Bottle Test System: Summary of 
Modifications to ISO 11734:1995

    The six modifications specified in this Appendix shall apply to 
the determination of the biodegradability of synthetic base fluids 
as measured by ISO 11734:1995. These modifications make the test 
more applicable to a marine environment and are listed below:
    1.  The laboratory shall use sea water in place of freshwater 
media.
    1.1  The sea water may be either natural or synthetic. The 
allowable salinity range is 20-30 ppt.
    1.2  To reduce the shock to the microorganisms in the sediment, 
the salinity of the sediment's porewater shall be between 20-30 ppt.
    2.  The laboratory shall use natural marine or estuarine 
sediments in place of digested sludge as an inoculum. The VS of the 
sediments must be no less than 2%.
    2.1  Sediment should be used for testing as soon as possible 
after field collection. If required, the laboratory can store the 
sediment for a maximum period of two months prior to use. The test 
sediment shall be stored in the dark at 4 deg.C.
    2.2  The laboratory shall use the sediment mixing procedure 
specified in Appendix 3 to Subpart A of part 435 to spike the test 
sediment with base fluids. The final concentration will be 2000 mg 
carbon/Kg dry weight sediment. No less than 25 g dry weight of the 
spiked sediment shall be used per 125 ml serum bottle. The volume of 
sediment and seawater in the bottle shall be 75 ml.
    3.  The temperature of incubation shall be 
29<plus-minus>1 deg.C.
    4.  The pH is maintained at the level of natural sea water, not 
at 7.0 as referenced in ISO 11734:1995.
    5.  The optional use of a trace metals solution as specified in 
method ISO 11734:1995 shall not be used as part of these test 
modifications.
    6.  The laboratory shall conduct the test for 275 days. The 
laboratory may seek approval of alternate test durations under the 
approval procedures specified at 40 CFR 136.4 and 136.5. Any 
modification of this method, beyond those expressly permitted, shall 
be considered a major modification subject to application and 
approval of alternate test procedures under 40 CFR 136.4 and 136.5.

Appendix 5 to Subpart A of Part 435--Determination of Crude Oil 
Contamination in Non-Aqueous Drilling Fluids by Gas Chromatography/Mass 
Spectrometry (GC/MS)

1.0  Scope and Application

    1.1  This method determines crude (formation) oil contamination, 
or other petroleum oil contamination, in non-aqueous drilling fluids 
(NAFs) by comparing the gas chromatography/mass spectrometry (GC/MS) 
fingerprint scan and extracted ion scans of the test sample to that 
of an uncontaminated sample.
    1.2  This method can be used for monitoring oil contamination of 
NAFs or monitoring oil contamination of the base fluid used in the 
NAF formulations.
    1.3  Any modification of this method beyond those expressly 
permitted shall be considered as a major modification subject to 
application and approval of alternative test procedures under 40 CFR 
136.4 and 136.5.
    1.4  The gas chromatography/mass spectrometry portions of this 
method are restricted to use by, or under the supervision of 
analysts experienced in the use of GC/MS and in the interpretation 
of gas chromatograms and extracted ion scans. Each laboratory that 
uses this method must generate acceptable results using the 
procedures described in Sections 7, 9.2, and 12 of this appendix.

2.0  Summary of Method

    2.1  Analysis of NAF for crude oil contamination is a step-wise 
process. The analyst first performs a qualitative assessment of the 
presence or absence of crude oil in the sample. If crude oil is 
detected during this qualitative assessment, the analyst must 
perform a quantitative analysis of the crude oil concentration.
    2.2  A sample of NAF is centrifuged to obtain a solids free 
supernate.
    2.3  The test sample is prepared by removing an aliquot of the 
solids free supernate, spiking it with internal standard, and 
analyzing it using GC/MS techniques. The components are separated by 
the gas chromatograph and detected by the mass spectrometer.
    2.4  Qualitative identification of crude oil contamination is 
performed by comparing the Total Ion Chromatograph (TIC) scans and 
Extracted Ion Profile (EIP) scans of test sample to that of 
uncontaminated base fluids, and examining the profiles for 
chromatographic signatures diagnostic of oil contamination.
    2.5  The presence or absence of crude oil contamination observed 
in the full scan profiles and selected extracted ion profiles 
determines further sample quantitation and reporting requirements.
    2.6  If crude oil is detected in the qualitative analysis, 
quantitative analysis must be performed by calibrating the GC/MS 
using a designated NAF spiked with known concentrations of a 
designated oil.
    2.7  Quality is assured through reproducible calibration and 
testing of GC/MS system and through analysis of quality control 
samples.

3.0  Definitions

    3.1  A NAF is one in which the continuous-- phase is a water 
immiscible fluid such as an oleaginous material (e.g., mineral oil, 
enhance mineral oil, paraffinic oil, or synthetic material such as 
olefins and vegetable esters).
    3.2  TIC--Total Ion Chromatograph.
    3.3  EIP--Extracted Ion Profile.
    3.4  TCB--1,3,5-trichlorobenzene is used as the internal 
standard in this method.
    3.5  SPTM--System Performance Test Mix standards are used to 
establish retention times and monitor detection levels.

4.0  Interferences and Limitations

    4.1  Solvents, reagents, glassware, and other sample processing 
hardware may yield artifacts and/or elevated baselines causing 
misinterpretation of chromatograms.
    4.2  All Materials used in the analysis shall be demonstrated to 
be free from interferences by running method blanks. Specific 
selection of reagents and purification of solvents by distillation 
in all-glass systems may be required.
    4.3  Glassware shall be cleaned by rinsing with solvent and 
baking at 400  deg.C for a minimum of 1 hour.

[[Page 6903]]

    4.4  Interferences may vary from source to source, depending on 
the diversity of the samples being tested.
    4.5  Variations in and additions of base fluids and/or drilling 
fluid additives (emulsifiers, dispersants, fluid loss control 
agents, etc.) might also cause interferences and misinterpretation 
of chromatograms.
    4.6  Difference in light crude oils, medium crude oils, and 
heavy crude oils will result in different responses and thus 
different interpretation of scans and calculated percentages.

5.0  Safety

    5.1  The toxicity or carcinogenicity of each reagent used in 
this method has not been precisely determined; however each chemical 
shall be treated as a potential health hazard. Exposure to these 
chemicals should be reduced to the lowest possible level.
    5.2  Unknown samples may contain high concentration of volatile 
toxic compounds. Sample containers should be opened in a hood and 
handled with gloves to prevent exposure. In addition, all sample 
preparation should be conducted in a fume hood to limit the 
potential exposure to harmful contaminates.
    5.3  This method does not address all safety issues associated 
with its use. The laboratory is responsible for maintaining a safe 
work environment and a current awareness file of OSHA regulations 
regarding the safe handling of the chemicals specified in this 
method. A reference file of material safety data sheets (MSDSs) 
shall be available to all personnel involved in these analyses. 
Additional references to laboratory safety can be found in 
References 16.1 through 16.3.
    5.4  NAF base fluids may cause skin irritation, protective 
gloves are recommended while handling these samples.

6.0  Apparatus and Materials

    Note: Brand names, suppliers, and part numbers are for 
illustrative purposes only. No endorsement is implied. Equivalent 
performance may be achieved using apparatus and materials other than 
those specified here, but demonstration of equivalent performance 
meeting the requirements of this method is the responsibility of the 
laboratory.

    6.1  Equipment for glassware cleaning.
    6.1.1  Laboratory sink with overhead fume hood.
    6.1.2  Kiln--Capable of reaching 450  deg.C within 2 hours and 
holding 450  deg.C within <plus-minus>10  deg.C, with temperature 
controller and safety switch (Cress Manufacturing Co., Santa Fe 
Springs, CA B31H or X31TS or equivalent).
    6.2  Equipment for sample preparation.
    6.2.1  Laboratory fume hood.
    6.2.2  Analytical balance--Capable of weighing 0.1 mg.
    6.2.3  Glassware.
    6.2.3.1  Disposable pipettes--Pasteur, 150 mm long by 5 mm ID 
(Fisher Scientific 13-678-6A, or equivalent) baked at 400  deg.C for 
a minimum of 1 hour.
    6.2.3.2  Glass volumetric pipettes or gas tight syringes--1.0-mL 
<plus-minus> 1% and 0.5-mL <plus-minus> 1%.
    6.2.3.3  Volumetric flasks--Glass, class A, 10-mL, 50-mL and 
100-mL.
    6.2.3.4--Sample vials--Glass, 1- to 3-mL (baked at 400  deg.C 
for a minimum of 1 hour) with PTFE-lined screw or crimp cap.
    6.2.3.5  Centrifuge and centrifuge tubes--Centrifuge capable of 
10,000 rpm, or better, (International Equipment Co., IEC Centra MP4 
or equivalent) and 50-mL centrifuge tubes (Nalgene, Ultratube, Thin 
Wall 25 x 89 mm, #3410-2539).
    6.3  Gas Chromatograph/Mass Spectrometer (GC/MS):
    6.3.1  Gas Chromatograph--An analytical system complete with a 
temperature-programmable gas chromatograph suitable for split/
splitless injection and all required accessories, including 
syringes, analytical columns, and gases.
    6.3.1.1  Column--30 m (or 60 m)  x  0.32 mm ID (or 0.25 mm ID) 
1<greek-m>m film thickness (or 0.25<greek-m>m film thickness) 
silicone-coated fused-silica capillary column (J&W Scientific DB-5 
or equivalent).
    6.3.2  Mass Spectrometer--Capable of scanning from 35 to 500 amu 
every 1 sec or less, using 70 volts (nominal) electron energy in the 
electron impact ionization mode (Hewlett Packard 5970MS or 
comparable).
    6.3.3  GC/MS interface--the interface is a capillary-direct 
interface from the GC to the MS.
    6.3.4--Data system--A computer system must be interfaced to the 
mass spectrometer. The system must allow the continuous acquisition 
and storage on machine-readable media of all mass spectra obtained 
throughout the duration of the chromatographic program. The computer 
must have software that can search any GC/MS data file for ions of a 
specific mass and that can plot such ion abundance versus retention 
time or scan number. This type of plot is defined as an Extracted 
Ion Current Profile (EIP). Software must also be available that 
allows integrating the abundance in any total ion chromatogram (TIC) 
or EIP between specified retention time or scan-number limits. It is 
advisable that the most recent version of the EPA/NIST Mass Spectral 
Library be available.

7.0  Reagents and Standards

    7.1  Methylene chloride--Pesticide grade or equivalent. Use when 
necessary for sample dilution.
    7.2  Standards--Prepare from pure individual standard materials 
or purchase as certified solutions. If compound purity is 96% or 
greater, the weight may be used without correction to compute the 
concentration of the standard.
    7.2.1  Crude Oil Reference--Obtain a sample of a crude oil with 
a known API gravity. This oil shall be used in the calibration 
procedures.
    7.2.2  Synthetic Base Fluid--Obtain a sample of clean internal 
olefin (IO) Lab drilling fluid (as sent from the supplier--has not 
been circulated downhole). This drilling fluid shall be used in the 
calibration procedures.
    7.2.3  Internal standard--Prepare a 0.01 g/mL solution of 1,3,5-
trichlorobenzene (TCB). Dissolve 1.0 g of TCB in methylene chloride 
and dilute to volume in a 100-mL volumetric flask. Stopper, vortex, 
and transfer the solution to a 150-mL bottle with PTFE-lined cap. 
Label appropriately, and store at -5  deg.C to 20  deg.C. Mark the 
level of the meniscus on the bottle to detect solvent loss.
    7.2.4  GC/MS system performance test mix (SPTM) standards--The 
SPTM standards shall contain octane, decane, dodecane, tetradecane, 
tetradecene, toluene, ethylbenzene, 1,2,4-trimethylbenzene, 1-
methylnaphthalene and 1,3-dimethylnaphthalene. These compounds can 
be purchased individually or obtained as a mixture (i.e. Supelco, 
Catalog No. 4-7300). Prepare a high concentration of the SPTM 
standard at 62.5 mg/mL in methylene chloride. Prepare a medium 
concentration SPTM standard at 1.25 mg/mL by transferring 1.0 mL of 
the 62.5 mg/mL solution into a 50 mL volumetric flask and diluting 
to the mark with methylene chloride. Finally, prepare a low 
concentration SPTM standard at 0.125 mg/mL by transferring 1.0 mL of 
the 1.25 mg/mL solution into a 10-mL volumetric flask and diluting 
to the mark with methylene chloride.
    7.2.5  Crude oil/drilling fluid calibration standards--Prepare a 
4-point crude oil/drilling fluid calibration at concentrations of 0% 
(no spike--clean drilling fluid), 0.5%, 1.0%, and 2.0% by weight 
according to the procedures outlined in this appendix using the 
Reference Crude Oil:
    7.2.5.1  Label 4 jars with the following identification: Jar 1--
0%Ref-IOLab, Jar 2--0.5%Ref-IOLab, Jar 3--1%Ref-IOLab, and Jar 4--
2%Ref-IOLab.
    7.2.5.2  Weigh 4, 50-g aliquots of well mixed IO Lab drilling 
fluid into each of the 4 jars.
    7.2.5.3  Add Reference Oil at 0.5%, 1.0%, and 2.0% by weight to 
jars 2, 3, and 4 respectively. Jar 1 shall not be spiked with 
Reference Oil in order to retain a ``0%'' oil concentration.
    7.2.5.4  Thoroughly mix the contents of each of the 4 jars, 
using clean glass stirring rods.
    7.2.5.5  Transfer (weigh) a 30-g aliquot from Jar 1 to a labeled 
centrifuge tube. Centrifuge the aliquot for a minimum of 15 min at 
approximately 15,000 rpm, in order to obtain a solids free 
supernate. Weigh 0.5 g of the supernate directly into a tared and 
appropriately labeled GC straight vial. Spike the 0.5-g supernate 
with 500 <greek-m>L of the 0.01g/mL 1,3,5-trichlorobenzene internal 
standard solution (see Section 7.2.3 of this appendix), cap with a 
Teflon lined crimp cap, and vortex for ca. 10 sec.
    7.2.5.6  Repeat step 7.2.5.5 except use an aliquot from Jar 2.
    7.2.5.7  Repeat step 7.2.5.5 except use an aliquot from Jar 3.
    7.2.5.8  Repeat step 7.2.5.5 except use an aliquot from Jar 4.
    7.2.5.9  These 4 crude/oil drilling fluid calibration standards 
are now used for qualitative and quantitative GC/MS analysis.
    7.2.6  Precision and recovery standard (mid level crude oil/
drilling fluid calibration standard)--Prepare a mid point crude oil/ 
drilling fluid calibration using IO Lab drilling fluid and Reference 
Oil at a concentration of 1.0% by weight. Prepare this standard 
according to the procedures outlined in Section 7.2.5.1 through 
7.2.5.5 of this appendix, with the exception that only ``Jar

[[Page 6904]]

3'' needs to be prepared. Remove and spike with internal standard, 
as many 0.5-g aliquots as needed to complete the GC/MS analysis (see 
Section 11.6 of this appendix--bracketing authentic samples every 12 
hours with precision and recovery standard) and the initial 
demonstration exercise described in Section 9.2 of this appendix.
    7.2.7  Stability of standards
    7.2.7.1  When not used, standards shall be stored in the dark, 
at -5 to -20  deg.C in screw-capped vials with PTFE-lined lids. 
Place a mark on the vial at the level of the solution so that 
solvent loss by evaporation can be detected. Bring the vial to room 
temperature prior to use.
    7.2.7.2  Solutions used for quantitative purposes shall be 
analyzed within 48 hours of preparation and on a monthly basis 
thereafter for signs of degradation. A standard shall remain 
acceptable if the peak area remains within <plus-minus>15% of the 
area obtained in the initial analysis of the standard.

8.0  Sample Collection Preservation and Storage

    8.1  Collect NAF and base fluid samples in 100- to 200-mL glass 
bottles with PTFE- or aluminum foil lined caps.
    8.2  Samples collected in the field shall be stored refrigerated 
until time of preparation.
    8.3  Sample and extract holding times for this method have not 
yet been established. However, based on initial experience with the 
method, samples should be analyzed within seven to ten days of 
collection and extracts should be analyzed within seven days of 
preparation.
    8.4  After completion of GC/MS analysis, extracts shall be 
refrigerated at 4  deg.C until further notification of sample 
disposal.

9.0  Quality Control

    9.1  Each laboratory that uses this method is required to 
operate a formal quality assurance program (Reference 16.4). The 
minimum requirements of this program shall consist of an initial 
demonstration of laboratory capability, and ongoing analysis of 
standards, and blanks as a test of continued performance, analyses 
of spiked samples to assess accuracy and analysis of duplicates to 
assess precision. Laboratory performance shall be compared to 
established performance criteria to determine if the results of 
analyses meet the performance characteristics of the method.
    9.1.1  The analyst shall make an initial demonstration of the 
ability to generate acceptable accuracy and precision with this 
method. This ability shall be established as described in Section 
9.2 of this appendix.
    9.1.2  The analyst is permitted to modify this method to improve 
separations or lower the cost of measurements, provided all 
performance requirements are met. Each time a modification is made 
to the method, the analyst is required to repeat the calibration 
(Section 10.4 of this appendix) and to repeat the initial 
demonstration procedure described in Section 9.2 of this appendix.
    9.1.3  Analyses of blanks are required to demonstrate freedom 
from contamination. The procedures and criteria for analysis of a 
blank are described in Section 9.3 of this appendix.
    9.1.4  Analysis of a matrix spike sample is required to 
demonstrate method accuracy. The procedure and QC criteria for 
spiking are described in Section 9.4 of this appendix.
    9.1.5  Analysis of a duplicate field sample is required to 
demonstrate method precision. The procedure and QC criteria for 
duplicates are described in Section 9.5 of this appendix.
    9.1.6  Analysis of a sample of the clean NAF(s) (as sent from 
the supplier--i.e., has not been circulated downhole) used in the 
drilling operations is required.
    9.1.7  The laboratory shall, on an ongoing basis, demonstrate 
through calibration verification and the analysis of the precision 
and recovery standard (Section 7.2.6 of this appendix) that the 
analysis system is in control. These procedures are described in 
Section 11.6 of this appendix.
    9.1.8  The laboratory shall maintain records to define the 
quality of data that is generated.
    9.2  Initial precision and accuracy--The initial precision and 
recovery test shall be performed using the precision and recovery 
standard (1% by weight Reference Oil in IO Lab drilling fluid). The 
laboratory shall generate acceptable precision and recovery by 
performing the following operations.
    9.2.1  Prepare four separate aliquots of the precision and 
recovery standard using the procedure outlined in Section 7.2.6 of 
this appendix. Analyze these aliquots using the procedures outlined 
in Section 11 of this appendix.
    9.2.2  Using the results of the set of four analyses, compute 
the average recovery (X) in weight percent and the standard 
deviation of the recovery(s) for each sample.
    9.2.3  If s and X meet the acceptance criteria of 80% to 110%, 
system performance is acceptable and analysis of samples may begin. 
If, however, s exceeds the precision limit or X falls outside the 
range for accuracy, system performance is unacceptable. In this 
event, review this method, correct the problem, and repeat the test.
    9.2.4  Accuracy and precision--The average percent recovery (P) 
and the standard deviation of the percent recovery (Sp) Express the 
accuracy assessment as a percent recovery interval from P-
2S<INF>p</INF> to P+2S<INF>p</INF>. For example, if P=90% and 
S<INF>p</INF>=10% for four analyses of crude oil in NAF, the 
accuracy interval is expressed as 70% to 110%. Update the accuracy 
assessment on a regular basis.
    9.3  Blanks--Rinse glassware and centrifuge tubes used in the 
method with 30 mL of methylene chloride, remove a 0.5-g aliquot of 
the solvent, spike it with the 500 <greek-m>L of the internal 
standard solution (Section 7.2.3 of this appendix) and analyze a 1-
<greek-m>L aliquot of the blank sample using the procedure in 
Section 11 of this appendix. Compute results per Section 12 of this 
appendix.
    9.4  Matrix spike sample--Prepare a matrix spike sample 
according to procedure outlined in Section 7.2.6 of this appendix. 
Analyze the sample and calculate the concentration (% oil) in the 
drilling fluid and % recovery of oil from the spiked drilling fluid 
using the methods described in Sections 11 and 12 of this appendix.
    9.5  Duplicates--A duplicate field sample shall be prepared 
according to procedures outlined in Section 7.3 of this appendix and 
analyzed according to Section 11 of this appendix. The relative 
percent difference (RPD) of the calculated concentrations shall be 
less than 15%.
    9.5.1  Analyze each of the duplicates per the procedure in 
Section 11 of this appendix and compute the results per Section 12 
of this appendix.
    9.5.2  Calculate the relative percent difference (RPD) between 
the two results per the following equation:

RPD = [D<INF>1</INF> - D<INF>2</INF>]/[(D<INF>1</INF> + 
D<INF>2</INF>)/2]  x  100  [1]

where:

D<INF>1</INF> = Concentration of crude oil in the sample; and
D<INF>2</INF> = Concentration of crude oil in the duplicate sample.

    9.5.3  If the RPD criteria are not met, the analytical system 
shall be judged to be out of control, and the problem must be 
immediately identified and corrected, and the sample batch re-
analyzed.
    9.6  Prepare the clean NAF sample according to procedures 
outlined in Section 7.3 of this appendix. Ultimately the oil-
equivalent concentration from the TIC or EIP signal measured in the 
clean NAF sample shall be subtracted from the corresponding 
authentic field samples in order to calculate the true contaminant 
concentration (% oil) in the field samples (see Section 12 of this 
appendix).
    9.7  The specifications contained in this method can be met if 
the apparatus used is calibrated properly, and maintained in a 
calibrated state. The standards used for initial precision and 
recovery (Section 9.2 of this appendix) and ongoing precision and 
recovery (Section 11.6 of this appendix) shall be identical, so that 
the most precise results will be obtained. The GC/MS instrument will 
provide the most reproducible results if dedicated to the setting 
and conditions required for the analyses given in this method.
    9.8  Depending on specific program requirements, field 
replicates and field spikes of crude oil into samples may be 
required when this method is used to assess the precision and 
accuracy of the sampling and sample transporting techniques.

10.0  Calibration

    10.1  Establish gas chromatographic/mass spectrometer operating 
conditions given in Table 1 of this appendix. Perform the GC/MS 
system hardware-tune as outlined by the manufacture. The gas 
chromatograph shall be calibrated using the internal standard 
technique.

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


     Table 1.--Gas Chromatograph/Mass Spectrometer (GC/MS) Operation
                               Conditions
------------------------------------------------------------------------
                 Parameter                             Setting
------------------------------------------------------------------------
Injection pot.............................  280  deg.C

[[Page 6905]]

 
Transfer line.............................  280  deg.C
Detector..................................  280  deg.C
Initial Temperature.......................  50  deg.C
Initial Time..............................  5 minutes
Ramp......................................  50 to 300  deg.C @ 5  deg.C
                                             per minute
Final Temperature.........................  300  deg.C
Final Hold................................  20 minutes or until all
                                             peaks have eluted
Carrier Gas...............................  Helium
Flow rate.................................  As required for standard
                                             operation
Split ratio...............................  As required to meet
                                             performance criteria
                                             (~1:100)
Mass range................................  35 to 600 amu
------------------------------------------------------------------------


           Table 2.--Approximate Retention Time for Compounds
------------------------------------------------------------------------
                                                             Approximate
                                                              retention
                          Compound                               time
                                                              (minutes)
------------------------------------------------------------------------
Toluene....................................................          5.6
Octane, n-C<INF>8</INF>...............................................          7.2
Ethylbenzene...............................................         10.3
1,2,4-Trimethylbenzene.....................................         16.0
Decane, -C<INF>10</INF>...............................................         16.1
TCB (Internal Standard)....................................         21.3
Dodecane, -C<INF>12</INF>.............................................         22.9
1-Methylnaphthalene........................................         26.7
1-Tetradecene..............................................         28.4
Tetradecane, -C<INF>14</INF>..........................................         28.7
1,3-Dimethylnaphthalene....................................         29.7
------------------------------------------------------------------------

    10.2  Internal standard calibration procedure--1,3,5-
trichlorobenzene (TCB) has been shown to be free of interferences 
from diesel and crude oils and is a suitable internal standard.
    10.3  The system performance test mix standards prepared in 
Section 7.2.4 of this appendix shall be used to establish retention 
times and establish qualitative detection limits.
    10.3.1  Spike a 500-mL aliquot of the 1.25 mg/mL SPTM standard 
with 500 <greek-m>L of the TCB internal standard solution.
    10.3.2  Inject 1.0 <greek-m>L of this spiked SPTM standard onto 
the GC/MS in order to demonstrate proper retention times. For the 
GC/MS used in the development of this method, the ten compounds in 
the mixture had typical retention times shown in Table 2 of this 
appendix. Extracted ion scans for m/z 91 and 105 showed a maximum 
abundance of 400,000.
    10.3.3  Spike a 500-mL aliquot of the 0.125 mg/mL SPTM standard 
with 500 <greek-m>L of the TCB internal standard solution.
    10.3.4  Inject 1.0 <greek-m>L of this spiked SPTM standard onto 
the GC/MS to monitor detectable levels. For the GC/MS used in the 
development of this test, all ten compounds showed a minimum peak 
height of three times signal to noise. Extracted ion scans for m/z 
91 and 105 showed a maximum abundance of 40,000.
    10.4  GC/MS crude oil/drilling fluid calibration--There are two 
methods of quantification: Total Area Integration (C<INF>8</INF>-
C<INF>13</INF>) and EIP Area Integration using m/z's 91 and 105. The 
Total Area Integration method should be used as the primary 
technique for quantifying crude oil in NAFs. The EIP Area 
Integration method should be used as a confirmatory technique for 
NAFs. However, the EIP Area Integration method shall be used as the 
primary method for quantifying oil in enhanced mineral oil (EMO) 
based drilling fluid. Inject 1.0 <greek-m>L of each of the four 
crude oil/drilling fluid calibration standards prepared in Section 
7.2.5 of this appendix into the GC/MS. The internal standard should 
elute approximately 21-22 minutes after injection. For the GC/MS 
used in the development of this method, the internal standard peak 
was (35 to 40)% of full scale at an abundance of about 3.5e+07.
    10.4.1  Total Area Integration Method--For each of the four 
calibration standards obtain the following: Using a straight 
baseline integration technique, obtain the total ion chromatogram 
(TIC) area from C<INF>8</INF> to C<INF>13</INF>. Obtain the TIC area 
of the internal standard (TCB). Subtract the TCB area from the 
C<INF>8</INF>-C<INF>13</INF> area to obtain the true C<INF>8</INF>-
C<INF>13</INF> area. Using the C<INF>8</INF>-C<INF>13</INF> and TCB 
areas, and known internal standard concentration, generate a linear 
regression calibration using the internal standard method. The 
r<SUP>2</SUP> value for the linear regression curve shall be greater 
than or equal to 0.998. Some synthetic fluids might have peaks that 
elute in the window and would interfere with the analysis. In this 
case the integration window can be shifted to other areas of scan 
where there are no interfering peaks from the synthetic base fluid.
    10.4.2  EIP Area Integration--For each of the four calibration 
standards generate Extracted Ion Profiles (EIPs) for m/z 91 and 105. 
Using straight baseline integration techniques, obtain the following 
EIP areas:
    10.4.2.1  For m/z 91 integrate the area under the curve from 
approximately 9 minutes to 21-22 minutes, just prior to but not 
including the internal standard.
    10.4.2.2  For m/z 105 integrate the area under the curve from 
approximately 10.5 minutes to 26.5 minutes.
    10.4.2.3  Obtain the internal standard area from the TCB in each 
of the four calibration standards, using m/z 180.
    10.4.2.4  Using the EIP areas for TCB, m/z 91 and m/z105, and 
the known concentration of internal standard, generate linear 
regression calibration curves for the target ions 91 and 105 using 
the internal standard method. The r<SUP>2</SUP> value for each of 
the EIP linear regression curves shall be greater than or equal to 
0.998.
    10.4.2.5  Some base fluids might produce a background level that 
would show up on the extracted ion profiles, but there should not be 
any real peaks (signal to noise ratio of 1:3) from the clean base 
fluids.

11.0  Procedure

    11.1  Sample Preparation--
    11.1.1  Mix the authentic field sample (drilling fluid) well. 
Transfer (weigh) a 30-g aliquot of the sample to a labeled 
centrifuge tube.
    11.1.2  Centrifuge the aliquot for a minimum of 15 min at 
approximately 15,000 rpm, in order to obtain a solids free 
supernate.
    11.1.3  Weigh 0.5 g of the supernate directly into a tared and 
appropriately labeled GC straight vial.
    11.1.4  Spike the 0.5-g supernate with 500 <greek-m>L of the 
0.01g/mL 1,3,5-trichlorobenzene internal standard solution (see 
Section 7.2.3 of this appendix), cap with a Teflon lined crimp cap, 
and vortex for ca. 10 sec.
    11.1.5  The sample is ready for GC/MS analysis.
    11.2  Gas Chromatography.
    Table 1 of this appendix summarizes the recommended operating 
conditions for the GC/MS. Retention times for the n-alkanes obtained 
under these conditions are given in Table 2 of this appendix. Other 
columns, chromatographic conditions, or detectors may be used if 
initial precision and accuracy requirements (Section 9.2 of this 
appendix) are met. The system shall be calibrated according to the 
procedures outlined in Section 10 of this appendix, and verified 
every 12 hours according to Section 11.6 of this appendix.
    11.2.1  Samples shall be prepared (extracted) in a batch of no 
more than 20 samples. The batch shall consist of 20 authentic 
samples, 1 blank (Section 9.3 of this appendix), 1 matrix spike 
sample (9.4), and 1 duplicate field sample (9.5), and a prepared 
sample of the corresponding clean NAF used in the drilling process.
    11.2.2  An analytical sequence shall be analyzed on the GC/MS 
where the 3 SPTM standards (Section 7.2.4 of this appendix) 
containing internal standard are analyzed first, followed by 
analysis of the four GC/MS crude oil/drilling fluid calibration 
standards (Section 7.2.5 of this appendix), analysis of the blank, 
matrix spike sample, the duplicate sample, the clean NAF sample, 
followed by the authentic samples.
    11.2.3  Samples requiring dilution due to excessive signal shall 
be diluted using methylene chloride.
    11.2.4  Inject 1.0 <greek-m>L of the test sample or standard 
into the GC, using the conditions in Table 1 of this appendix.
    11.2.5  Begin data collection and the temperature program at the 
time of injection.
    11.2.6  Obtain a TIC and EIP fingerprint scans of the sample 
(Table 3 of this appendix).
    11.2.7  If the area of the C<INF>8</INF> to C<INF>13</INF> peaks 
exceeds the calibration range of the system, dilute a fresh aliquot 
of the test sample weighing 0.50-g and re-analyze.
    11.2.8  Determine the C<INF>8</INF> to C<INF>13</INF> TIC area, 
the TCB internal standard area, and the areas for the m/z 91 and 105 
EIPs. These shall be used in the calculation of oil concentration in 
the samples (see Section 12 of this appendix).

[[Page 6906]]



                 Table 3.--Recommended Ion Mass Numbers
------------------------------------------------------------------------
                                     Corresponding    Typical rentention
    Selected ion mass numbers     aromatic compounds    time (minutes)
------------------------------------------------------------------------
91..............................  Methylbenzene.....                6.0
                                  Ethylbenzene......               10.3
                                  1,4-                             10.9
                                   Dimethylbenzene.
                                  1,3-                             10.9
                                   Dimethylbenzene.
                                  1,2-                             11.9
                                   Dimethylbenzene.
105.............................  1,3,5-                           15.1
                                   Trimethylbenzene.
                                  1,2,4-                           16.0
                                   Trimethylbenzene.
                                  1,2,3-                           17.4
                                   Trimethylbenzene.
156.............................  2,6-                             28.9
                                   Dimethylnaphthale
                                   ne.
                                  1,2-                             29.4
                                   Dimethylnaphthale
                                   ne.
                                  1,3-                             29.7
                                   Dimethylnaphthale
                                   ne.
------------------------------------------------------------------------

    11.2.9  Observe the presence of peaks in the EIPs that would 
confirm the presence of any target aromatic compounds. Using the EIP 
areas and EIP linear regression calibrations compare the abundance 
of the aromatic peaks, and if appropriate, determine approximate 
crude oil contamination in the sample for each of the target ions.
    11.3  Qualitative Identification--See Section 17 of this 
appendix for schematic flowchart.
    11.3.1  Qualitative identification shall be accomplished by 
comparison of the TIC and EIP area data from an authentic sample to 
the TIC and EIP area data from the calibration standards (Section 
12.4 of this appendix). Crude oil shall be identified by the 
presence of C<INF>10</INF> to C<INF>13</INF> n-alkanes and 
corresponding target aromatics.
    11.3.2  Using the calibration data, establish the identity of 
the C<INF>8</INF> to C<INF>13</INF> peaks in the chromatogram of the 
sample. Using the calibration data, establish the identity of any 
target aromatics present on the extracted ion scans.
    11.3.3  Crude oil is not present in a detectable amount in the 
sample if there are no target aromatics seen on the extracted ion 
scans. The experience of the analyst shall weigh heavily in the 
determination of the presence of peaks at a signal-to-noise ratio of 
3 or greater.
    11.3.4  If the chromatogram shows n-alkanes from C<INF>8</INF> 
to C<INF>13</INF> and target aromatics to be present, contamination 
by crude oil or diesel shall be suspected and quantitative analysis 
shall be determined. If there are no n-alkanes present that are not 
seen on the blank, and no target aromatics are seen, the sample can 
be considered to be free of contamination.
    11.4  Quantitative Identification--
    11.4.1  Determine the area of the peaks from C<INF>8</INF> to 
C<INF>13</INF> as outlined in the calibration section (10.4.1 of 
this appendix). If the area of the peaks for the sample is greater 
than that for the clean NAF (base fluid) use the crude oil/drilling 
fluid calibration TIC linear regression curve to determine 
approximate crude oil contamination.
    11.4.2  Using the EIPs outlined in Section 10.4.2 of this 
appendix, determine the presence of any target aromatics. Using the 
integration techniques outlined in Section 10.4.2 of this appendix, 
obtain the EIP areas for m/z 91 and 105. Use the crude oil/drilling 
fluid calibration EIP linear regression curves to determine 
approximate crude oil contamination.
    11.5  Complex Samples--
    11.5.1  The most common interferences in the determination of 
crude oil can be from mineral oil, diesel oil, and proprietary 
additives in drilling fluids.
    11.5.2  Mineral oil can typically be identified by its lower 
target aromatic content, and narrow range of strong peaks.
    11.5.3  Diesel oil can typically be identified by low amounts of 
n-alkanes from C<INF>7</INF> to C<INF>9</INF>, and the absence of n-
alkanes greater than C<INF>25</INF>.
    11.5.4  Crude oils can usually be distinguished by the presence 
of high aromatics, increased intensities of C<INF>8</INF> to 
C<INF>13</INF> peaks, and/ or the presence of higher hydrocarbons of 
C<INF>25</INF> and greater (which may be difficult to see in some 
synthetic fluids at low contamination levels).
    11.5.4.1  Oil condensates from gas wells are low in molecular 
weight and will normally produce strong chromatographic peaks in the 
C<INF>8</INF>-C<INF>13</INF> range. If a sample of the gas 
condensate crude oil from the formation is available, the oil can be 
distinguished from other potential sources of contamination by using 
it to prepare a calibration standard.
    11.5.4.2  Asphaltene crude oils with API gravity 20 may not 
produce chromatographic peaks strong enough to show contamination at 
levels of the calibration. Extracted ion peaks should be easier to 
see than increased intensities for the C<INF>8</INF> to 
C<INF>13</INF> peaks. If a sample of asphaltene crude from the 
formation is available, a calibration standard shall be prepared.
    11.6  System and Laboratory Performance--
    11.6.1  At the beginning of each 8-hour shift during which 
analyses are performed, GC crude oil/drilling fluid calibration and 
system performance test mixes shall be verified. For these tests, 
analysis of the medium-level calibration standard (1-% Reference Oil 
in IO Lab drilling fluid, and 1.25 mg/mL SPTM with internal 
standard) shall be used to verify all performance criteria. 
Adjustments and/or re-calibration (per Section 10 of this appendix) 
shall be performed until all performance criteria are met. Only 
after all performance criteria are met may samples and blanks be 
analyzed.
    11.6.2  Inject 1.0 <greek-m>L of the medium-level GC/MS crude 
oil/drilling fluid calibration standard into the GC instrument 
according to the procedures in Section 11.2 of this appendix. Verify 
that the linear regression curves for both TIC area and EIP areas 
are still valid using this continuing calibration standard.
    11.6.3  After this analysis is complete, inject 1.0 <greek-m>L 
of the 1.25 mg/mL SPTM (containing internal standard) into the GC 
instrument and verify the proper retention times are met (see Table 
2 of this appendix).
    11.6.4  Retention times--Retention time of the internal 
standard. The absolute retention time of the TCB internal standard 
shall be within the range 21.0 <plus-minus> 0.5 minutes. Relative 
retention times of the n-alkanes: The retention times of the n-
alkanes relative to the TCB internal standard shall be similar to 
those given in Table 2 of this appendix.

12.0  Calculations

    The concentration of oil in NAFs drilling fluids shall be 
computed relative to peak areas between C<INF>8</INF> and 
C<INF>13</INF> (using the Total Area Integration method) or total 
peak areas from extracted ion profiles (using the Extracted Ion 
Profile Method). In either case, there is a measurable amount of 
peak area, even in clean drilling fluid samples, due to spurious 
peaks and electrometer ``noise'' that contributes to the total 
signal measured using either of the quantification methods. In this 
procedure, a correction for this signal is applied, using the blank 
or clean sample correction technique described in American Society 
for Testing Materials (ASTM) Method D-3328-90, Comparison of 
Waterborne Oil by Gas Chromatography. In this method, the ``oil 
equivalents'' measured in a blank sample by total area gas 
chromatography are subtracted from that determined for a field 
sample to arrive at the most accurate measure of oil residue in the 
authentic sample.
    12.1  Total Area Integration Method
    12.1.1  Using C<INF>8</INF> to C<INF>13</INF> TIC area, the TCB 
area in the clean NAF sample and the TIC linear regression curve, 
compute the oil equivalent concentration of the C<INF>8</INF> to 
C<INF>13</INF> retention time range in the clean NAF.

    Note: The actual TIC area of the C<INF>8</INF> to C<INF>13</INF> 
is equal to the C<INF>8</INF> to C<INF>13</INF> area minus the area 
of the TCB.

    12.1.2  Using the corresponding information for the authentic 
sample, compute the oil equivalent concentration of the 
C<INF>8</INF> to C<INF>13</INF> retention time range in the 
authentic sample.
    12.1.3  Calculate the concentration (% oil) of oil in the sample 
by subtracting the oil

[[Page 6907]]

equivalent concentration (% oil) found in the clean NAF from the oil 
equivalent concentration (% oil) found in the authentic sample.
    12.2  EIP Area Integration Method
    12.2.1  Using either m/z 91 or 105 EIP areas, the TCB area in 
the clean NAF sample, and the appropriate EIP linear regression 
curve, compute the oil equivalent concentration of the in the clean 
NAF.
    12.2.2  Using the corresponding information for the authentic 
sample, compute its oil equivalent concentration.
    12.2.3  Calculate the concentration (% oil) of oil in the sample 
by subtracting the oil equivalent concentration (% oil) found in the 
clean NAF from the oil equivalent concentration (% oil) found in the 
authentic sample.

13.0  Method Performance

    13.1  Specification in this method are adopted from EPA Method 
1663, Differentiation of Diesel and Crude Oil by GC/FID (Reference 
16.5).
    13.2  Single laboratory method performance using an Internal 
Olefin (IO) drilling fluid fortified at 0.5% oil using a 35 API 
gravity oil was:

Precision and accuracy 94<plus-minus>4%
Accuracy interval--86.3% to 102%
Relative percent difference in duplicate analysis--6.2%

14.0  Pollution Prevention

    14.1  The solvent used in this method poses little threat to the 
environment when recycled and managed properly.

15.0  Waste Management

    15.1  It is the laboratory's responsibility to comply with all 
federal, state, and local regulations governing waste management, 
particularly the hazardous waste identification rules and land 
disposal restriction, and to protect the air, water, and land by 
minimizing and controlling all releases from fume hoods and bench 
operations. Compliance with all sewage discharge permits and 
regulations is also required.
    15.2  All authentic samples (drilling fluids) failing the RPE 
(fluorescence) test (indicated by the presence of fluorescence) 
shall be retained and classified as contaminated samples. Treatment 
and ultimate fate of these samples is not outlined in this SOP.
    15.3  For further information on waste management, consult ``The 
Waste Management Manual for Laboratory Personnel'', and ``Less is 
Better: Laboratory Chemical Management for Waste Reduction'', both 
available from the American Chemical Society's Department of 
Government Relations and Science Policy, 1155 16th Street NW, 
Washington, DC 20036.

16.0  References

    16.1  Carcinogens--``Working With Carcinogens.'' Department of 
Health, Education, and Welfare, Public Health Service, Centers for 
Disease Control (available through National Technical Information 
Systems, 5285 Port Royal Road, Springfield, VA 22161, document no. 
PB-277256): August 1977.
    16.2  ``OSHA Safety and Health Standards, General Industry [29 
CFR 1910], Revised.'' Occupational Safety and Health Administration, 
OSHA 2206. Washington, DC: January 1976.
    16.3  ``Handbook of Analytical Quality Control in Water and 
Wastewater Laboratories.'' USEPA, EMSSL-CI, EPA-600/4-79-019. 
Cincinnati, OH: March 1979.
    16.4  ``Method 1663, Differentiation of Diesel and Crude Oil by 
GC/FID, Methods for the Determination of Diesel, Mineral, and Crude 
Oils in Offshore Oil and Gas Industry Discharges, EPA 821-R-92-008, 
Office of Water Engineering and Analysis Division, Washington, DC: 
December 1992.

Appendix 6 to Subpart A of Part 435--Reverse Phase Extraction (RPE) 
Method for Detection of Oil Contamination in Non-Aqueous Drilling 
Fluids (NAF)

1.0  Scope and Application

    1.1  This method is used for determination of crude or formation 
oil, or other petroleum oil contamination, in non-aqueous drilling 
fluids (NAFs).
    1.2  This method is intended as a positive/negative test to 
determine a presence of crude oil in NAF prior to discharging drill 
cuttings from offshore production platforms.
    1.3  This method is for use in the Environmental Protection 
Agency's (EPA's) survey and monitoring programs under the Clean 
Water Act, including monitoring of compliance with the Gulf of 
Mexico NPDES General Permit for monitoring of oil contamination in 
drilling fluids.
    1.4  This method has been designed to show positive 
contamination for 5% of representative crude oils at a concentration 
of 0.1% in drilling fluid (vol/vol), 50% of representative crude 
oils at a concentration of 0.5%, and 95% of representative crude 
oils at a concentration of 1%.
    1.5  Any modification of this method, beyond those expressly 
permitted, shall be considered a major modification subject to 
application and approval of alternate test procedures under 40 CFR 
Parts 136.4 and 136.5.
    1.6  Each laboratory that uses this method must demonstrate the 
ability to generate acceptable results using the procedure in 
Section 9.2 of this appendix.

2.0  Summary of Method

    2.1  An aliquot of drilling fluid is extracted using isopropyl 
alcohol.
    2.2  The mixture is allowed to settle and then filtered to 
separate out residual solids.
    2.3  An aliquot of the filtered extract is charged onto a 
reverse phase extraction (RPE) cartridge.
    2.4  The cartridge is eluted with isopropyl alcohol.
    2.5  Crude oil contaminates are retained on the cartridge and 
their presence (or absence) is detected based on observed 
fluorescence using a black light.

3.0  Definitions

    3.1  A NAF is one in which the continuous phase is a water 
immiscible fluid such as an oleaginous material (e.g., mineral oil, 
enhance mineral oil, paraffinic oil, or synthetic material such as 
olefins and vegetable esters).

4.0  Interferences

    4.1  Solvents, reagents, glassware, and other sample-processing 
hardware may yield artifacts that affect results. Specific selection 
of reagents and purification of solvents may be required.
    4.2  All materials used in the analysis shall be demonstrated to 
be free from interferences under the conditions of analysis by 
running laboratory reagent blanks as described in Section 9.5 of 
this appendix.

5.0  Safety

    5.1  The toxicity or carcinogenicity of each reagent used in 
this method has not been precisely determined; however, each 
chemical shall be treated as a potential health hazard. Exposure to 
these chemicals should be reduced to the lowest possible level. 
Material Safety Data Sheets (MSDSs) shall be available for all 
reagents.
    5.2  Isopropyl alcohol is flammable and should be used in a 
well-ventilated area.
    5.3  Unknown samples may contain high concentration of volatile 
toxic compounds. Sample containers should be opened in a hood and 
handled with gloves to prevent exposure. In addition, all sample 
preparation should be conducted in a well-ventilated area to limit 
the potential exposure to harmful contaminants. Drilling fluid 
samples should be handled with the same precautions used in the 
drilling fluid handling areas of the drilling rig.
    5.4  This method does not address all safety issues associated 
with its use. The laboratory is responsible for maintaining a safe 
work environment and a current awareness file of OSHA regulations 
regarding the safe handling of the chemicals specified in this 
method. A reference file of material safety data sheets (MSDSs) 
shall be available to all personnel involved in these analyses. 
Additional information on laboratory safety can be found in 
References 16.1-16.2.

6.0  Equipment and Supplies

    Note: Brand names, suppliers, and part numbers are for 
illustrative purposes only. No endorsement is implied. Equivalent 
performance may be achieved using apparatus and materials other than 
those specified here, but demonstration of equivalent performance 
that meets the requirements of this method is the responsibility of 
the laboratory.

    6.1  Sampling equipment.
    6.1.1  Sample collection bottles/jars--New, pre-cleaned bottles/
jars, lot-certified to be free of artifacts. Glass preferable, 
plastic acceptable, wide mouth approximately 1-L, with Teflon-lined 
screw cap.
    6.2  Equipment for glassware cleaning.
    6.2.1  Laboratory sink.
    6.2.2  Oven--Capable of maintaining a temperature within 
<plus-minus>5 deg.C in the range of 100-250  deg.C.
    6.3  Equipment for sample extraction.
    6.3.1  Vials--Glass, 25 mL and 4 mL, with Teflon-lined screw 
caps, baked at 200-250  deg.C for 1-h minimum prior to use.
    6.3.2  Gas-tight syringes--Glass, various sizes, 0.5 mL to 2.5 
mL (if spiking of drilling fluids with oils is to occur).
    6.3.3  Auto pipetters--various sizes, 0.1 mL, 0.5 mL, 1 to 5 mL 
delivery, and 10 mL

[[Page 6908]]

delivery, with appropriate size disposable pipette tips, calibrated 
to within <plus-minus>0.5%.
    6.3.4  Glass stirring rod.
    6.3.5  Vortex mixer.
    6.3.6  Disposable syringes--Plastic, 5 mL.
    6.3.7  Teflon syringe filter, 25-mm, 0.45<greek-m>m pore size--
Acrodisc<Register> CR Teflon (or equivalent).
    6.3.8  Reverse Phase Extraction C<INF>18</INF> Cartridge--Waters 
Sep-Pak<Register>Plus, C<INF>18</INF> Cartridge, 360 mg of sorbent 
(or equivalent).
    6.3.9  SPE vacuum manifold--Supelco Brand, 12 unit (or 
equivalent). Used as support for cartridge/syringe assembly only. 
Vacuum apparatus not required.
    6.4  Equipment for fluorescence detection.
    6.4.1  Black light--UV Lamp, Model UVG 11, Mineral Light Lamp, 
Shortwave 254 nm, or Longwave 365 nm, 15 volts, 60 Hz, 0.16 amps (or 
equivalent).
    6.4.2  Black box--cartridge viewing area. A commercially 
available ultraviolet viewing cabinet with viewing lamp, or 
alternatively, a cardboard box or equivalent, approximately 
14" x 7.5" x 7.5" in size and painted flat black inside. Lamp 
positioned in fitted and sealed slot in center on top of box. Sample 
cartridges sit in a tray, ca. 6" from lamp. Cardboard flaps cut on 
top panel and side of front panel for sample viewing and sample 
cartridge introduction, respectively.
    6.4.3  Viewing platform for cartridges. Simple support (hand 
made vial tray--black in color) for cartridges so that they do not 
move during the fluorescence testing.

7.0  Reagents and Standards

    7.1  Isopropyl alcohol--99% purity.
    7.2  NAF--Appropriate NAF as sent from the supplier (has not 
been circulated downhole). Use the clean NAF corresponding to the 
NAF being used in the current drilling operation.
    7.3  Standard crude oil--NIST SRM 1582 petroleum crude oil.

8.0  Sample Collection, Preservation, and Storage

    8.1 Collect approximately one liter of representative sample 
(NAF, which has been circulated downhole) in a glass bottle or jar. 
Cover with a Teflon lined cap. To allow for a potential need to re-
analyze and/or re-process the sample, it is recommended that a 
second sample aliquot be collected.
    8.2  Label the sample appropriately.
    8.3  All samples must be refrigerated at 0-4  deg.C from the 
time of collection until extraction (40 CFR Part 136, Table II).
    8.4  All samples must be analyzed within 28 days of the date and 
time of collection (40 CFR Part 136, Table II).

9.0  Quality Control

    9.1  Each laboratory that uses this method is required to 
operate a formal quality assurance program (Reference 16.3). The 
minimum requirements of this program consist of an initial 
demonstration of laboratory capability, and ongoing analyses of 
blanks and spiked duplicates to assess accuracy and precision and to 
demonstrate continued performance. Each field sample is analyzed in 
duplicate to demonstrate representativeness.
    9.1.1  The analyst shall make an initial demonstration of the 
ability to generate acceptable accuracy and precision with this 
method. This ability is established as described in Section 9.2 of 
this appendix.
    9.1.2  Preparation and analysis of a set of spiked duplicate 
samples to document accuracy and precision. The procedure for the 
preparation and analysis of these samples is described in Section 
9.4 of this appendix.
    9.1.3  Analyses of laboratory reagent blanks are required to 
demonstrate freedom from contamination. The procedure and criteria 
for preparation and analysis of a reagent blank are described in 
Section 9.5 of this appendix.
    9.1.4  The laboratory shall maintain records to define the 
quality of the data that is generated.
    9.1.5  Accompanying QC for the determination of oil in NAF is 
required per analytical batch. An analytical batch is a set of 
samples extracted at the same time, to a maximum of 10 samples. Each 
analytical batch of 10 or fewer samples must be accompanied by a 
laboratory reagent blank (Section 9.5 of this appendix), 
corresponding NAF reference blanks (Section 9.6 of this appendix), a 
set of spiked duplicate samples blank (Section 9.4 of this 
appendix), and duplicate analysis of each field sample. If greater 
than 10 samples are to be extracted at one time, the samples must be 
separated into analytical batches of 10 or fewer samples.
    9.2  Initial demonstration of laboratory capability. To 
demonstrate the capability to perform the test, the analyst shall 
analyze two representative unused drilling fluids (e.g., internal 
olefin-based drilling fluid, vegetable ester-based drilling fluid), 
each prepared separately containing 0.1%, 1%, and 2% or a 
representative oil. Each drilling fluid/concentration combination 
shall be analyzed 10 times, and successful demonstration will yield 
the following average results for the data set:

0.1% oil--Detected in 20% of samples
1% oil--Detected in >75% of samples
2% oil--Detected in 90% of samples

    9.3  Sample duplicates.
    9.3.1  The laboratory shall prepare and analyze (Section 11.2 
and 11.4 of this appendix) each authentic sample in duplicate, from 
a given sampling site or, if for compliance monitoring, from a given 
discharge.
    9.3.2  The duplicate samples must be compared versus the 
prepared corresponding NAF blank.
    9.3.3  Prepare and analyze the duplicate samples according to 
procedures outlined in Section 11 of this appendix.
    9.3.4  The results of the duplicate analyses are acceptable if 
each of the results give the same response (fluorescence or no 
fluorescence). If the results are different, sample non-homogenicity 
issues may be a concern. Prepare the samples again, ensuring a well-
mixed sample prior to extraction. Analyze the samples once again.
    9.3.5  If different results are obtained for the duplicate a 
second time, the analytical system is judged to be out of control 
and the problem shall be identified and corrected, and the samples 
re-analyzed.
    9.4  Spiked duplicates--Laboratory prepared spiked duplicates 
are analyzed to demonstrate acceptable accuracy and precision.
    9.4.1  Preparation and analysis of a set of spiked duplicate 
samples with each set of no more than 10 field samples is required 
to demonstrate method accuracy and precision and to monitor matrix 
interferences (interferences caused by the sample matrix). A field 
NAF sample expected to contain less than 0.5% crude oil (and 
documented to not fluoresce as part of the sample batch analysis) 
shall be spiked with 1% (by volume) of suitable reference crude oil 
and analyzed as field samples, as described in Section 11 of this 
appendix. If no low-level drilling fluid is available, then the 
unused NAF can be used as the drilling fluid sample.
    9.5  Laboratory reagent blanks--Laboratory reagent blanks are 
analyzed to demonstrate freedom from contamination.
    9.5.1  A reagent blank is prepared by passing 4 mL of the 
isopropyl alcohol through a Teflon syringe filter and collecting the 
filtrate in a 4-mL glass vial. A Sep Pak<Register> C<INF>18</INF> 
cartridge is then preconditioned with 3 mL of isopropyl alcohol. A 
0.5-mL aliquot of the filtered isopropyl alcohol is added to the 
syringe barrel along with 3.0 mL of isopropyl alcohol. The solvent 
is passed through the preconditioned Sep Pak<Register> cartridge. An 
additional 2-mL of isopropyl alcohol is eluted through the 
cartridge. The cartridge is now considered the ``reagent blank'' 
cartridge and is ready for viewing (analysis). Check the reagent 
blank cartridge under the black light for fluorescence. If the 
isopropyl alcohol and filter are clean, no fluorescence will be 
observed.
    9.5.2  If fluorescence is detected in the reagent blank 
cartridge, analysis of the samples is halted until the source of 
contamination is eliminated and a prepared reagent blank shows no 
fluorescence under a black light. All samples shall be associated 
with an uncontaminated method blank before the results may be 
reported for regulatory compliance purposes.
    9.6  NAF reference blanks--NAF reference blanks are prepared 
from the NAFs sent from the supplier (NAF that has not been 
circulated downhole) and used as the reference when viewing the 
fluorescence of the test samples.
    9.6.1  A NAF reference blank is prepared identically to the 
authentic samples. Place a 0.1 mL aliquot of the ``clean'' NAF into 
a 25-mL glass vial. Add 10 mL of isopropyl alcohol to the vial. Cap 
the vial. Vortex the vial for approximately 10 sec. Allow the solids 
to settle for approximately 15 minutes. Using a 5-mL syringe, draw 
up 4 mL of the extract and filter it through a PTFE syringe filter, 
collecting the filtrate in a 4-mL glass vial. Precondition a Sep 
Pak<Register> C<INF>18</INF> cartridge with 3 mL of isopropyl 
alcohol. Add a 0.5-mL aliquot of the filtered extract to the syringe 
barrel along with 3.0 mL of isopropyl alcohol. Pass the extract and 
solvent through the preconditioned Sep Pak<Register> cartridge. Pass 
an additional 2-mL of isopropyl alcohol through the cartridge. The 
cartridge is now considered the NAF blank cartridge and is ready for 
viewing (analysis). This cartridge is used as the reference 
cartridge for determining the absence or presence of fluorescence in 
all authentic drilling fluid

[[Page 6909]]

samples that originate from the same NAF. That is, the specific NAF 
reference blank cartridge is put under the black light along with a 
prepared cartridge of an authentic sample originating from the same 
NAF material. The fluorescence or absence of fluorescence in the 
authentic sample cartridge is determined relative to the NAF 
reference cartridge.
    9.6.2  Positive control solution, equivalent to 1% crude oil 
contaminated mud extract, is prepared by dissolving 87 mg of 
standard crude oil into 10.00 mL of methylene chloride. Then mix 40 
<greek-m>L of this solution into 10.00 mL of IPA. Transfer 0.5 mL of 
this solution into a preconditioned C18 cartridge, followed by 2 ml 
of IPA.

10.0  Calibration and Standardization

    10.1  Calibration and standardization methods are not employed 
for this procedure.

11.0  Procedure

    This method is a screening-level test. Precise and accurate 
results can be obtained only by strict adherence to all details.
    11.1  Preparation of the analytical batch.
    11.1.1  Bring the analytical batch of samples to room 
temperature.
    11.1.2  Using a large glass stirring rod, mix the authentic 
sample thoroughly.
    11.1.3  Using a large glass stirring rod, mix the clean NAF 
(sent from the supplier) thoroughly.
    11.2  Extraction.
    11.2.1  Using an automatic positive displacement pipetter and a 
disposable pipette tip transfer 0.1-mL of the authentic sample into 
a 25-mL vial.
    11.2.2  Using an automatic pipetter and a disposable pipette tip 
dispense a 10-mL aliquot of solvent grade isopropyl alcohol (IPA) 
into the 25 mL vial.
    11.2.3  Cap the vial and vortex the vial for ca. 10-15 seconds.
    11.2.4  Let the sample extract stand for approximately 5 
minutes, allowing the solids to separate.
    11.2.5  Using a 5-mL disposable plastic syringe remove 4 mL of 
the extract from the 25-mL vial.
    11.2.6  Filter 4 mL of extract through a Teflon syringe filter 
(25-mm diameter, 0.45 <greek-m>m pore size), collecting the filtrate 
in a labeled 4-mL vial.
    11.2.7  Dispose of the PFTE syringe filter.
    11.2.8  Using a black permanent marker, label a Sep 
Pak<Register> C<INF>18</INF> cartridge with the sample 
identification.
    11.2.9  Place the labeled Sep Pak<Register> C<INF>18</INF> 
cartridge onto the head of a SPE vacuum manifold.
    11.2.10  Using a 5-mL disposable plastic syringe, draw up 
exactly 3-mL (air free) of isopropyl alcohol.
    11.2.11  Attach the syringe tip to the top of the C<INF>18</INF> 
cartridge.
    11.2.12  Condition the C<INF>18</INF> cartridge with the 3-mL of 
isopropyl alcohol by depressing the plunger slowly.

    Note: Depress the plunger just to the point when no liquid 
remains in the syringe barrel. Do not force air through the 
cartridge. Collect the eluate in a waste vial.

    11.2.13  Remove the syringe temporarily from the top of the 
cartridge, then remove the plunger, and finally reattach the syringe 
barrel to the top of the C<INF>18</INF> cartridge.
    11.2.14  Using automatic pipetters and disposable pipette tips, 
transfer 0.5 mL of the filtered extract into the syringe barrel, 
followed by a 3.0-mL transfer of isopropyl alcohol to the syringe 
barrel.
    11.2.15  Insert the plunger and slowly depress it to pass only 
the extract and solvent through the preconditioned C<INF>18</INF> 
cartridge.

    Note: Depress the plunger just to the point when no liquid 
remains in the syringe barrel. Do not force air through the 
cartridge. Collect the eluate in a waste vial.

    11.2.16  Remove the syringe temporarily from the top of the 
cartridge, then remove the plunger, and finally reattach the syringe 
barrel to the top of the C<INF>18</INF> cartridge.
    11.2.17  Using an automatic pipetter and disposable pipette tip, 
transfer 2.0 mL of isopropyl alcohol to the syringe barrel.
    11.2.18  Insert the plunger and slowly depress it to pass the 
solvent through the C<INF>18</INF> cartridge.

    Note: Depress the plunger just to the point when no liquid 
remains in the syringe barrel. Do not force air through the 
cartridge. Collect the eluate in a waste vial.

    11.2.19  Remove the syringe and labeled C<INF>18</INF> cartridge 
from the top of the SPE vacuum manifold.
    11.2.20  Prepare a reagent blank according to the procedures 
outlined in Section 9.5 of this appendix.
    11.2.21  Prepare the necessary NAF reference blanks for each 
type of NAF encountered in the field samples according to the 
procedures outlined in Section 9.6 of this appendix.
    11.2.22  Prepare the positive control (1% crude oil equivalent) 
according to Section 9.6.2 of this appendix.
    11.3  Reagent blank fluorescence testing.
    11.3.1  Place the reagent blank cartridge in a black box, under 
a black light.
    11.3.2  Determine the presence or absence of fluorescence for 
the reagent blank cartridge. If fluorescence is detected in the 
blank, analysis of the samples is halted until the source of 
contamination is eliminated and a prepared reagent blank shows no 
fluorescence under a black light. All samples must be associated 
with an uncontaminated method blank before the results may be 
reported for regulatory compliance purposes.
    11.4  Sample fluorescence testing.
    11.4.1  Place the respective NAF reference blank (Section 9.6 of 
this appendix) onto the tray inside the black box.
    11.4.2  Place the authentic field sample cartridge (derived from 
the same NAF as the NAF reference blank) onto the tray, adjacent and 
to the right of the NAF reference blank.
    11.4.3  Turn on the black light.
    11.4.4  Compare the fluorescence of the sample cartridge with 
that of the negative control cartridge (NAF blank, Section 9.6.1 of 
this appendix) and positive control cartridge (1% crude oil 
equivalent, Section 9.6.2 of this appendix).
    11.4.5  If the fluorescence of the sample cartridge is equal to 
or brighter than the positive control cartridge (1% crude oil 
equivalent, Section 9.6.2 of this appendix), the sample is 
considered contaminated. Otherwise, the sample is clean.

12.0  Data Analysis and Calculations

    Specific data analysis techniques and calculations are not 
performed in this SOP.

13.0  Method Performance

    This method was validated through a single laboratory study, 
conducted with rigorous statistical experimental design and 
interpretation (Reference 16.4).

14.0  Pollution Prevention

    14.1  The solvent used in this method poses little threat to the 
environment when recycled and managed properly.

15.0  Waste Management

    15.1  It is the laboratory's responsibility to comply with all 
Federal, State, and local regulations governing waste management, 
particularly the hazardous waste identification rules and land 
disposal restriction, and to protect the air, water, and land by 
minimizing and controlling all releases from bench operations. 
Compliance with all sewage discharge permits and regulations is also 
required.
    15.2  All authentic samples (drilling fluids) failing the 
fluorescence test (indicated by the presence of fluorescence) shall 
be retained and classified as contaminated samples. Treatment and 
ultimate fate of these samples is not outlined in this SOP.
    15.3  For further information on waste management, consult ``The 
Waste Management Manual for Laboratory Personnel,'' and ``Less is 
Better: Laboratory Chemical Management for Waste Reduction,'' both 
available from the American Chemical Society's Department of 
Government Relations and Science Policy, 1155 16th Street, NW, 
Washington, DC 20036.

16.0  References

    16.1  ``Carcinogen--Working with Carcinogens,'' Department of 
Health, Education, and Welfare, Public Health Service, Center for 
Disease Control, National Institute for Occupational Safety and 
Health, Publication No. 77-206, August 1977.
    16.2  ``OSHA Safety and Health Standards, General Industry,'' 
(29 CFR 1910), Occupational Safety and Health Administration, OSHA 
2206 (Revised, January 1976).
    16.3  ``Handbook of Analytical Quality Control in Water and 
Wastewater Laboratories,'' USEPA, EMSL-Ci, Cincinnati, OH 45268, 
EPA-600/4-79-019, March 1979.
    16.4  Report of the Laboratory Evaluation of Static Sheen Test 
Replacements--Reverse Phase Extraction (RPE) Method for Detecting 
Oil Contamination in Synthetic Based Mud (SBM). October 1998. 
Available from API, 1220 L Street, NW, Washington, DC 20005-4070, 
202-682-8000.

Appendix 7 to Subpart A of Part 435--API Recommended Practice 13B-2

1. Description

    a. This procedure is specifically intended to measure the amount 
of non-aqueous drilling fluid (NAF) base fluid from cuttings 
generated during a drilling operation. This procedure is a retort 
test which measures all oily material (NAF base fluid) and water 
released from a cuttings sample when heated

[[Page 6910]]

in a calibrated and properly operating ``Retort'' instrument.
    b. In this retort test a known mass of cuttings is heated in the 
retort chamber to vaporize the liquids associated with the sample. 
The NAF base fluid and water vapors are then condensed, collected, 
and measured in a precision graduated receiver.


    Note: Obtaining a representative sample requires special 
attention to the details of sample handling (e.g., location, method, 
frequency). See Addendum A and B for minimum requirements for 
collecting representative samples. Additional sampling procedures in 
a given area may be specified by the NPDES permit controlling 
authority.

2. Equipment

    a. Retort instrument--The recommended retort instrument has a 
50-cm<SUP>3</SUP> volume with an external heating jacket.
    Retort Specifications:
    1. Retort assembly--retort body, cup and lid.
    (a) Material: 303 stainless steel or equivalent.
    (b) Volume: Retort cup with lid.
    Cup Volume: 50-cm<SUP>3</SUP>.
    Precision: <plus-minus>0.25-cm<SUP>3</SUP>.
    2. Condenser--capable of cooling the oil and water vapors below 
their liquification temperature.
    3. Heating jacket--nominal 350 watts.
    4. Temperature control--capable of limiting temperature of 
retort to at least 930  deg.F (500  deg.C) and enough to boil off 
all NAFs.
    b. Liquid receiver (10-cm<SUP>3</SUP>, 20-cm<SUP>3</SUP>)--the 
10-cm<SUP>3</SUP> and 20-cm<SUP>3</SUP> receivers are specially 
designed cylindrical glassware with rounded bottom to facilitate 
cleaning and funnel-shaped top to catch falling drops. For 
compliance monitoring under the NPDES program, the analyst shall use 
the 10-cm<SUP>3</SUP> liquid receiver with 0.1 ml graduations to 
achieve greater accuracy.
    1. Receiver specifications:
    Total volume: 10-cm<SUP>3</SUP>, 20-cm<SUP>3</SUP>.
    Precision (0 to 100%): <plus-minus>0.05 cm<SUP>3</SUP>, 
<plus-minus>0.05 cm<SUP>3</SUP>.
    Outside diameter: 10-mm, 13-mm.
    Wall thickness: 1.5<plus-minus>0.1mm, 1.2<plus-minus>0.1mm.
    Frequency of graduation marks (0 to 100%): 0.10-cm<SUP>3</SUP>, 
0.10-cm<SUP>3</SUP>.
    Calibration: To contain ``TC'' @ 20 deg.C.
    Scale: cm<SUP>3</SUP>, cm<SUP>3</SUP>
    2. Material--Pyrex<Register> or equivalent glass.
    c. Toploading balance--capable of weighing 2000 g and precision 
of at least 0.1 g. Unless motion is a problem, the analyst shall use 
an electronic balance. Where motion is a problem, the analyst may 
use a triple beam balance.
    d. Fine steel wool (No. 000)--for packing retort body.
    e. Thread sealant lubricant: high temperature lubricant, e.g. 
Never-Seez<Register> or equivalent.
    f. Pipe cleaners--to clean condenser and retort stem.
    g. Brush--to clean receivers.
    h. Retort spatula--to clean retort cup.
    i. Corkscrew--to remove spent steel wool.

3. Procedure

    a. Clean and dry the retort assembly and condenser.
    b. Pack the retort body with steel wool.
    c. Apply lubricant/sealant to threads of retort cup and retort 
stem.
    d. Weigh and record the total mass of the retort cup, lid, and 
retort body with steel wool. This is mass (A), grams.
    e. Collect a representative cuttings sample (see Note in Section 
1 of this appendix).
    f. Partially fill the retort cup with cuttings and place the lid 
on the cup.
    g. Screw the retort cup (with lid) onto the retort body, weigh 
and record the total mass. This is mass (B), grams.
    h. Attach the condenser. Place the retort assembly into the 
heating jacket.
    i. Weigh and record the mass of the clean and dry liquid 
receiver. This is mass (C), grams. Place the receiver below 
condenser outlet.
    j. Turn on the retort. Allow it to run a minimum of 1 hour.

    Note: If solids boil over into receiver, the test shall be 
rerun. Pack the retort body with a greater amount of steel wool and 
repeat the test.

    k. Remove the liquid receiver. Allow it to cool. Record the 
volume of water recovered. This is (V), cm\3\.

    Note: If an emulsion interface is present between the oil and 
water phases, heating the interface may break the emulsion. As a 
suggestion, remove the retort assembly from the heating jacket by 
grasping the condenser. Carefully heat the receiver along the 
emulsion band by gently touching the receiver for short intervals 
with the hot retort assembly. Avoid boiling the liquids. After the 
emulsion interface is broken, allow the liquid receiver to cool. 
Read the water volume at the lowest point of the meniscus.

    l. Weigh and record the mass of the receiver and its liquid 
contents (oil plus water). This is mass (D), grams.
    m. Turn off the retort. Remove the retort assembly and condenser 
from the heating jacket and allow them to cool. Remove the 
condenser.
    n. Weigh and record the mass of the cooled retort assembly 
without the condenser. This is mass (E), grams.
    o. Clean the retort assembly and condenser.

4. Calculations

    a. Calculate the mass of oil (NAF base fluid) from the cuttings 
as follows:
    1. Mass of the wet cuttings sample (M<INF>w</INF>) equals the 
mass of the retort assembly with the wet cuttings sample (B) minus 
the mass of the empty retort assembly (A).

M<INF>w</INF> = B-A  [1]

    2. Mass of the dry retorted cuttings (M<INF>D</INF>) equals the 
mass of the cooled retort assembly (E) minus the mass of the empty 
retort assembly (A).

M<INF>D</INF> = E-A  [2]

    3. Mass of the NAF base fluid (M<INF>BF</INF>) equals the mass 
of the liquid receiver with its contents (D) minus the sum of the 
mass of the dry receiver (C) and the mass of the water (V).

M<INF>BF</INF> = D-(C + V)  [3]


    Note: Assuming the density of water is 1 g/cm\3\, the volume of 
water is equivalent to the mass of the water.

    b. Mass balance requirement:
    The sum of M<INF>D</INF>, M<INF>BF</INF>, and V shall be within 
5% of the mass of the wet sample.

(M<INF>D</INF> + M<INF>BF</INF> + V)/M<INF>w</INF> = 0.95 to 1.05  
[4]

    The procedure shall be repeated if this requirement is not met.
    c. Reporting oil from cuttings:
    1. Assume that all oil recovered is NAF base fluid.
    2. The mass percent NAF base fluid retained on the cuttings 
(%BF<INF>i</INF>) for the sampled discharge ``i'' is equal to 100 
times the mass of the NAF base fluid (M<INF>BF</INF>) divided by the 
mass of the wet cuttings sample (M<INF>w</INF>).

%BF<INF>i</INF> = (M<INF>BF</INF>/M<INF>w</INF>)  x  100  [5]

    Operators discharging small volume NAF-cuttings discharges which 
do not occur during a NAF-cuttings discharge sampling interval 
(i.e., displaced interfaces, accumulated solids in sand traps, pit 
clean-out solids, or centrifuge discharges while cutting mud weight) 
shall either: (a) Measure the mass percent NAF base fluid retained 
on the cuttings (%BF<INF>SVD</INF>) for each small volume NAF-
cuttings discharges; or (b) use a default value of 25% NAF base 
fluid retained on the cuttings.
    3. The mass percent NAF base fluid retained on the cuttings is 
determined for all cuttings wastestreams and includes fines 
discharges and any accumulated solids discharged [see Section 4.c.6 
of this appendix for procedures on measuring or estimating the mass 
percent NAF base fluid retained on the cuttings (%BF) for dual 
gradient drilling seafloor discharges performed to ensure proper 
operation of subsea pumps].
    4. A mass NAF-cuttings discharge fraction (X, unitless) is 
calculated for all NAF-cuttings, fines, or accumulated solids 
discharges every time a set of retorts is performed (see Section 
4.c.6 of this appendix for procedures on measuring or estimating the 
mass NAF-cuttings discharge fraction (X) for dual gradient drilling 
seafloor discharges performed to ensure proper operation of subsea 
pumps). The mass NAF-cuttings discharge fraction (X) combines the 
mass of NAF-cuttings, fines, or accumulated solids discharged from a 
particular discharge over a set period of time with the total mass 
of NAF-cuttings, fines, or accumulated solids discharged into the 
ocean during the same period of time (see Addendum A and B of this 
appendix). The mass NAF-cuttings discharge fraction (X) for each 
discharge is calculated by direct measurement as:

X<INF>i</INF> = (F<INF>i</INF>)/(G)  [6]

where:

X<INF>i</INF> = Mass NAF-cuttings discharge fraction for NAF-
cuttings, fines, or accumulated solids discharge ``i'', (unitless)
F<INF>i</INF> = Mass of NAF-cuttings discharged from NAF-cuttings, 
fines, or accumulated solids discharge ``i'' over a specified period 
of time (see Addendum A and B of this appendix), (kg)
G = Mass of all NAF-cuttings discharges into the ocean during the 
same period of time as used to calculate F<INF>i</INF>, (kg)

    If an operator has more than one point of NAF-cuttings 
discharge, the mass faction (X<INF>i</INF>) must be determined by: 
(a) Direct measurement (see Equation 6 of this

[[Page 6911]]

Appendix); (b) using the following default values of 0.85 and 0.15 
for the cuttings dryer (e.g., horizontal centrifuge, vertical 
centrifuge, squeeze press, High-G linear shakers) and fines removal 
unit (e.g., decanting centrifuges, mud cleaners), respectively, when 
the operator is only discharging from the cuttings dryer and the 
fines removal unit; or (c) using direct measurement of 
``F<INF>i</INF>'' (see Equation 6 of this Appendix) for fines and 
accumulated solids, using Equation 6A of this Appendix to calculate 
``G<INF>EST</INF>'' for use as ``G'' in Equation 6 of this Appendix, 
and calculating the mass (kg) of NAF-cuttings discharged from the 
cuttings dryer (F<INF>i</INF>) as the difference between the mass of 
``G<INF>EST</INF>'' calculated in Equation 6A of this appendix (kg) 
and the sum of all fines and accumulated solids mass directly 
measured (kg) (see Equation 6 of this Appendix).
G<INF>EST</INF> = Estimated mass of all NAF-cuttings discharges into 
the ocean during the same period of time as used to calculate 
F<INF>i</INF> (see Equation 6 of this Appendix), (kg)  [6A]
where:

G<INF>EST</INF> = Hole Volume (bbl)  x  (396.9 kg/bbl)  x  (1 + Z/
100)
Z = The base fluid retained on cuttings limitation or standard (%) 
which apply to the NAF being discharge (see Secs. 435.13. and 
435.15).
Hole Volume (bbl) = [Cross-Section Area of NAF interval 
(in<SUP>2</SUP>)]  x  Average Rate of Penetration (feet/hr)  x  
period of time (min) used to calculate F<INF>i</INF> (see Equation 6 
of this Appendix)  x  (1 hr/60 min)  x  (1 bbl/5.61 ft<SUP>3</SUP>) 
x  (1 ft/12 in)<SUP>2</SUP>
Cross-Section Area of NAF interval (in<SUP>2</SUP>) = (3.14  x  [Bit 
Diameter (in)]<SUP>2</SUP>)/4
Bit Diameter (in) = Diameter of drilling bit for the NAF interval 
producing drilling cuttings during the same period of time as used 
to calculate F<INF>i</INF> (see Equation 6 of this Appendix)
Average Rate of Penetration (feet/hr) = Arithmetic average of rate 
of penetration into the formation during the same period of time as 
used to calculate F<INF>i</INF> (see Equation 6 of this Appendix)


    Note: Operators with one NAF-cuttings discharge may set the mass 
NAF-cuttings discharge fraction (X<INF>i</INF>) equal to 1.0.


    5. Each NAF-cuttings, fines, or accumulated solids discharge has 
an associated mass percent NAF base fluid retained on cuttings value 
(%BF) and mass NAF-cuttings discharge fraction (X) each time a set 
of retorts is performed. A single total mass percent NAF base fluid 
retained on cuttings value (%BF<INF>T</INF>) is calculated every 
time a set of retorts is performed. The single total mass percent 
NAF base fluid retained on cuttings value (%BF<INF>T</INF>) is 
calculated as:

%BF<INF>T,j</INF> = <greek-S>(X<INF>i</INF>) x (%BF<INF>i</INF>)  
[7]

where:

%BF<INF>T,j</INF> = Total mass percent NAF base fluid retained on 
cuttings value for retort set ``j'' (unitless as percentage, %)
X<INF>i</INF> = Mass NAF-cuttings discharge fraction for NAF-
cuttings, fines, or accumulated solids discharge ``i'', (unitless)
%BF<INF>i</INF> = Mass percent NAF base fluid retained on the 
cuttings for NAF-cuttings, fines, or accumulated solids discharge 
``i'' , (unitless as percentage, %)


    Note: <greek-S>X<INF>i</INF> = 1.

    Operators with one NAF-cuttings discharge may set 
%BF<INF>T,j</INF> equal to %BF<INF>i</INF>.
    6. Operators performing dual gradient drilling operations may 
require seafloor discharges of large cuttings (>\1/4\") to ensure 
the proper operation of subsea pumps (e.g., electrical submersible 
pumps). Operators performing dual gradient drilling operations which 
lead to seafloor discharges of large cuttings for the proper 
operation of subsea pumps shall either: (a) Measure the mass percent 
NAF base fluid retained on cuttings value (%BF) and mass NAF-
cuttings discharge fraction (X) for seafloor discharges each time a 
set of retorts is performed; (b) use the following set of default 
values, (%BF=14%; X=0.15); or (c) use a combination of (a) and (b) 
(e.g., use a default value for %BF and measure X).
    Additionally, operators performing dual gradient drilling 
operations which lead to seafloor discharges of large cuttings for 
the proper operation of subsea pumps shall also perform the 
following tasks:
    (a) Use side scan sonar or shallow seismic to determine the 
presence of high density chemosynthetic communities. Chemosynthetic 
communities are assemblages of tube worms, clams, mussels, and 
bacterial mats that occur at natural hydrocarbon seeps or vents, 
generally in water depths of 500 meters or deeper. Seafloor 
discharges of large cuttings for the proper operation of subsea 
pumps shall not be permitted within 1000 feet of a high density 
chemosynthetic community.
    (b) Seafloor discharges of large cuttings for the proper 
operation of subsea pumps shall be visually monitored and documented 
by a Remotely Operated Vehicle (ROV) within the tether limit 
(approximately 300 feet). The visual monitoring shall be conducted 
prior to each time the discharge point is relocated (cuttings 
discharge hose) and conducted along the same direction as the 
discharge hose position. Near-seabed currents shall be obtained at 
the time of the visual monitoring.
    (c) Seafloor discharges of large cuttings for the proper 
operation of subsea pumps shall be directed within a 150 foot radius 
of the wellbore.
    7. The weighted mass ratio averaged over all NAF well sections 
(%BF<INF>well</INF>) is the compliance value that is compared with 
the ``maximum weighted mass ratio averaged over all NAF well 
sections'' BAT discharge limitations (see the table in Sec. 435.13 
and footnote 5 of the table in Sec. 435.43) or the ``maximum 
weighted mass ratio averaged over all NAF well sections'' NSPS 
discharge limitations (see the table in Sec. 435.15 and footnote 5 
of the table in Sec. 435.45). The weighted mass ratio averaged over 
all NAF well sections (%BF<INF>well</INF>) is calculated as the 
arithmetic average of all total mass percent NAF base fluid retained 
on cuttings values (%BF<INF>T</INF>) and is given by the following 
expression:

%BF<INF>well</INF> = [j=1 to j=n <greek-S> (%BF<INF>T,j</INF>)]/n  
[8]

where:

%BF<INF>well</INF> = Weighted mass ratio averaged over all NAF well 
sections (unitless as percentage, %)
%BF<INF>T,j</INF> = Total mass percent NAF base fluid retained on 
cuttings value for retort set ``j'' (unitless as percentage, %)
n = Total number of retort sets performed over all NAF well sections 
(unitless)

    Small volume NAF-cuttings discharges which do not occur during a 
NAF-cuttings discharge sampling interval (i.e., displaced 
interfaces, accumulated solids in sand traps, pit clean-out solids, 
or centrifuge discharges while cutting mud weight) shall be mass 
averaged with the arithmetic average of all total mass percent NAF 
base fluid retained on cuttings values (see Equation 8 of this 
Appendix). An additional sampling interval shall be added to the 
calculation of the weighted mass ratio averaged over all NAF well 
sections (%BF<INF>well</INF>). The mass fraction of the small volume 
NAF-cuttings discharges (X<INF>SVD</INF>) will be determined by 
dividing the mass of the small volume NAF-cuttings discharges 
(F<INF>SVD</INF>) by the total mass of NAF-cuttings discharges for 
the well drilling operation (G<INF>WELL</INF> + F<INF>SVD</INF>).

X<INF>SVD</INF> = F<INF>SVD</INF> / (G<INF>WELL</INF> + 
F<INF>SVD</INF>)  [9]

where:

X<INF>SVD</INF> = mass fraction of the small volume NAF-cuttings 
discharges (unitless)
F<INF>SVD</INF> = mass of the small volume NAF-cuttings discharges 
(kg)
G<INF>WELL</INF> = mass of total NAF-cuttings from the well (kg)

    The mass of small volume NAF-cuttings discharges 
(F<INF>SVD</INF>) shall be determined by multiplying the density of 
the small volume NAF-cuttings discharges (<greek-r><INF>svd</INF>) 
times the volume of the small volume NAF-cuttings discharges 
(V<INF>SVD</INF>).

F<INF>SVD</INF> = <greek-r><INF>svd</INF>  x  V<INF>SVD</INF>  [10]

where:

F<INF>SVD</INF> = mass of small volume NAF-cuttings discharges (kg)
<greek-r><INF>svd</INF> = density of the small volume NAF-cuttings 
discharges (kg/bbl)
V<INF>SVD</INF> = volume of the small volume NAF-cuttings discharges 
(bbl)
    The density of the small volume NAF-cuttings discharges shall be 
measured. The volume of small volume discharges (V<INF>SVD</INF>) 
shall be either: (a) Be measured or (b) use default values of 10 bbl 
of SBF for each interface loss and 75 bbl of SBM for pit cleanout 
per well.
    The total mass of NAF-cuttings discharges for the well 
(G<INF>WELL</INF>) shall be either: (a) Measured; or (b) calculated 
by multiplying 1.0 plus the arithmetic average of all total mass 
percent NAF base fluid retained on cuttings values [see Equation 8 
of this Appendix] times the total hole volume (V<INF>WELL</INF>) for 
all NAF well sections times a default value for the density the 
formation of 2.5 g/cm<SUP>3</SUP> (396.9 kg/bbl).


[[Page 6912]]


[GRAPHIC] [TIFF OMITTED] TR22JA01.161

where:

G<INF>WELL</INF> = total mass of NAF-cuttings discharges for the 
well (kg)
[j = 1 to j = n <greek-S>2(%BF<INF>Tj</INF>)]/n = see Equation 8 of 
this Appendix (unitless as a percentage)
V<INF>WELL</INF> = total hole volume (V<INF>WELL</INF>) for all NAF 
well sections (bbl)

    The total hole volume of NAF well sections (V<INF>WELL</INF>) 
will be calculated as:
[GRAPHIC] [TIFF OMITTED] TR22JA01.170

    For wells where small volume discharges associated with cuttings 
are made, %BF<INF>WELL</INF> becomes:
[GRAPHIC] [TIFF OMITTED] TR22JA01.171


    Note: See Addendum A and B to determine the sampling frequency 
to determine the total number of retort sets required for all NAF 
well sections.

    8. The total number of retort sets (n) is increased by 1 for 
each sampling interval (see Section 2.4, Addendum A of this 
appendix) when all NAF cuttings, fines, or accumulated solids for 
that sampling interval are retained for no discharge. A zero 
discharge interval shall be at least 500 feet up to a maximum of 
three per day. This action has the effect of setting the total mass 
percent NAF base fluid retained on cuttings value (%BF<INF>T</INF>) 
at zero for that NAF sampling interval when all NAF cuttings, fines, 
or accumulated solids are retained for no discharge.
    9. Operators that elect to use the Best Management Practices 
(BMPs) for NAF-cuttings shall use the procedures outlined in 
Addendum B.

Addendum A to Appendix 7 to Subpart A of Part 435--Sampling of Cuttings 
Discharge Streams for use with API Recommended Practice 13B-2

1.0  Sampling Locations

    1.1  Each NAF-cuttings waste stream that discharges into the 
ocean shall be sampled and analyzed as detailed in Appendix 7. NAF-
cuttings discharges to the ocean may include discharges from primary 
shakers, secondary shakers, cuttings dryer, fines removal unit, 
accumulated solids, and any other cuttings separation device whose 
NAF-cuttings waste is discharged to the ocean. NAF-cuttings 
wastestreams not directly discharged to the ocean (e.g., NAF-
cuttings generated from shake shakers and sent to a cuttings dryer 
for additional processing) do not require sampling and analysis.
    1.2  The collected samples shall be representative of each NAF-
cuttings discharge. Operators shall conduct sampling to avoid the 
serious consequences of error (i.e., bias or inaccuracy). Operators 
shall collect NAF-cuttings samples near the point of origin and 
before the solids and liquid fractions of the stream have a chance 
to separate from one another. For example, operators shall collect 
shale shaker NAF-cuttings samples at the point where NAF-cuttings 
are coming off the shale shaker and not from a holding container 
downstream where separation of larger particles from the liquid can 
take place.
    1.3  Operators shall provide a simple schematic diagram of the 
solids control system and sample locations to the NPDES permit 
controlling authority.

2.0  Type of Sample and Sampling Frequency

    2.1  Each NAF-cuttings, fines, or accumulated solids discharge 
has an associated mass percent NAF base fluid retained on cuttings 
value (%BF) and mass NAF-cuttings discharge fraction (X) for each 
sampling interval (see Section 2.4 of this addendum). Operators 
shall collect a single discrete NAF-cuttings sample for each NAF-
cuttings waste stream discharged to the ocean during every sampling 
interval.
    2.2  Operators shall use measured depth in feet from the Kelly 
bushing when samples are collected.
    2.3  The NAF-cuttings samples collected for the mass fraction 
analysis (see Equation 6, Appendix 7 of Subpart A of this part) 
shall also be used for the retort analysis (see Equations 1-5, 
Appendix 7 of Subpart A of this part).
    2.4  Operators shall collect and analyze at least one set of 
NAF-cuttings samples per day while discharging. Operators engaged in 
fast drilling (i.e., greater than 500 linear NAF feet advancement of 
drill bit per day) shall collect and analyze one set of NAF-cuttings 
samples per 500 linear NAF feet of footage drilled. Operators are 
not required to collect and analyze more than three sets of NAF-
cuttings samples per day (i.e., three sampling intervals). Operators 
performing zero discharge of all NAF-cuttings (i.e., all NAF 
cuttings, fines, or accumulated solids retained for no discharge) 
shall use the following periods to count sampling intervals: (1) One 
sampling interval per day when drilling is less than 500 linear NAF 
feet advancement of drill bit per day; and (2) one sampling interval 
per 500 linear NAF feet of footage drilled with a maximum of three 
sampling intervals per day.
    2.5  The operator shall measure the individual masses 
(F<INF>i</INF>, kg) and sum total mass (G, kg) (see Equation 6, 
Appendix 7 of subpart A of this part) over a representative period 
of time (e.g., 10 minutes) during steady-state conditions for each 
sampling interval (see Section 2.4 of this addendum). The operator 
shall ensure that all NAF-cuttings are capture for mass analysis 
during the same sampling time period (e.g., 10 minutes) at 
approximately the same time (i.e., all individual mass samples 
collected within one hour of each other).
    2.6  Operators using Best Management Practices (BMPs) to control 
NAF-cuttings discharges shall follow the procedures in Addendum B to 
Appendix 7 of subpart A of 40 CFR 435.

3.0  Sample Size and Handling

    3.1  The volume of each sample depends on the volumetric flow 
rate (cm\3\/s) of the NAF-cuttings stream and the sampling time 
period (e.g., 10 minutes). Consequently, different solids control 
equipment units producing different NAF-cuttings waste streams at 
different volumetric flow rates will produce different size samples 
for the same period of time. Operators shall use appropriately sized 
sample containers for each NAF-cuttings waste stream to ensure no 
NAF-cuttings are spilled during sample collection. Operators shall 
use the same time period (e.g., 10 minutes) to collect NAF-cuttings 
samples from each NAF-cuttings waste stream. Each NAF-cuttings 
sample size shall be at least one gallon. Operators shall clearly 
mark each container to identify each NAF-cuttings sample.
    3.2  Operators shall not decant, heat, wash, or towel the NAF-
cuttings to remove NAF base fluid before mass and retort analysis.
    3.3  Operators shall first calculate the mass of each NAF-
cuttings sample and perform the mass ratio analysis (see Equation 6, 
Appendix 7 of subpart A of this part). Operators with only one NAF-
cuttings discharge may skip this step (see Section 4.c.4, Appendix 7 
of subpart A of this part).
    3.4  Operators shall homogenize (e.g., stirring, shaking) each 
NAF-cuttings sample prior to placing a sub-sample into the retort 
cup. The bottom of the NAF-cuttings sample container shall be 
examined to be sure that solids are not sticking to it.
    3.5  Operators shall then calculate the NAF base fluid retained 
on cuttings using the retort procedure (see Equations 1-5, Appendix 
7 of subpart A of this part). Operators shall start the retort 
analyses no more than two hours after collecting the first 
individual mass sample for the sampling interval .
    3.6  Operators shall not discharge any sample before 
successfully completing the mass and retort analyses [i.e., mass 
balance

[[Page 6913]]

requirements (see Section 4.b, Appendix 7 of subpart A of this part) 
are satisfied]. Operators shall immediately re-run the retort 
analyses if the mass balance requirements (see Equation 4, Appendix 
7 of subpart A of this part) are not within a tolerance of 5% (see 
Section 4.b, Equation 4, Appendix 7 of subpart A of this part).

4.0  Calculations

    4.1  Operators shall calculate a set of mass percent NAF base 
fluid retained on cuttings values (%BF) and mass NAF-cuttings 
discharge fractions (X) for each NAF-cuttings waste stream (see 
Section 1.1 of this addendum) for each sampling interval (see 
Section 2.4 of this addendum) using the procedures outlined in 
Appendix 7 of subpart A of this part.
    4.2  Operators shall tabulate the following data for each 
individual NAF-cuttings sample: (1) Date and time of NAF-cuttings 
sample collection; (2) time period of NAF-cuttings sample collection 
(see Section 3.1 of this addendum); (3) mass and volume of each NAF-
cuttings sample; (4) measured depth (feet) at NAF-cuttings sample 
collection (see Section 2.2 of this addendum); (5) respective linear 
feet of hole drilled represented by the NAF-cuttings sample (feet); 
and (6) the drill bit diameter (inches) used to generate the NAF-
cuttings sample cuttings.
    4.3  Operators shall calculate a single total mass percent NAF 
base fluid retained on cuttings value (%BF<INF>T</INF>) for each 
sampling interval (see Section 2.4 of this addendum) using the 
procedures outlined in Appendix 7 of Subpart A of this part.
    4.4  Operators shall tabulate the following data for each total 
mass percent NAF base fluid retained on cuttings value 
(%BF<INF>T</INF>) for each NAF-cuttings sampling interval: (1) Date 
and starting and stopping times of NAF-cuttings sample collection 
and retort analyses; (2) measured depth of well (feet) at start of 
NAF-cuttings sample collection (see Section 2.2 of this addendum); 
(3) respective linear feet of hole drilled represented by the NAF-
cuttings sample (feet); (4) the drill bit diameter (inches) used to 
generate the NAF-cuttings sample cuttings; and (5) annotation when 
zero discharge of NAF-cuttings is performed.
    4.5  Operators shall calculate the weighted mass ratio averaged 
over all NAF well sections (%BF<INF>well</INF>) using the procedures 
outlined in Appendix 7 of Subpart A of this part.
    4.6  Operators shall tabulate the following data for each 
weighted mass ratio averaged over all NAF well sections 
(%BF<INF>well</INF>) for each NAF well: (1) Starting and stopping 
dates of NAF well sections; (2) measured depth (feet) of all NAF 
well sections; (3) total number of sampling intervals (see Section 
2.4 and Section 2.6 of this addendum); (4) number of sampling 
intervals tabulated during any zero discharge operations; (5) total 
volume of zero discharged NAF-cuttings over entire NAF well 
sections; and (6) identification of whether BMPs were employed (see 
Addendum B of Appendix 7 of subpart A of this part).

Addendum B to Appendix 7 to Subpart A of Part 435-- Best Management 
Practices (BMPs) for use with API Recommended Practice 13B-2

1.0  Overview of BMPs

    1.1  Best Management Practices (BMPs) are inherently pollution 
prevention practices. BMPs may include the universe of pollution 
prevention encompassing production modifications, operational 
changes, material substitution, materials and water conservation, 
and other such measures. BMPs include methods to prevent toxic and 
hazardous pollutants from reaching receiving waters. Because BMPs 
are most effective when organized into a comprehensive facility BMP 
Plan, operators shall develop a BMP in accordance with the 
requirements in this addendum.
    1.2  The BMP requirements contained in this appendix were 
compiled from several Regional permits, an EPA guidance document 
(i.e., Guidance Document for Developing Best Management Practices 
(BMP)'' (EPA 833-B-93-004, U.S. EPA, 1993)), and draft industry 
BMPs. These common elements represent the appropriate mix of broad 
directions needed to complete a BMP Plan along with specific tasks 
common to all drilling operations.
    1.3  Operators are not required to use BMPs if all NAF-cuttings 
discharges are monitored in accordance with Appendix 7 of Subpart A 
of this part.

2.0  BMP Plan Purpose and Objectives

    2.1  Operators shall design the BMP Plan to prevent or minimize 
the generation and the potential for the discharge of NAF from the 
facility to the waters of the United States through normal 
operations and ancillary activities. The operator shall establish 
specific objectives for the control of NAF by conducting the 
following evaluations.
    2.2  The operator shall identify and document each NAF well that 
uses BMPs before starting drilling operations and the anticipated 
total feet to be drilled with NAF for that particular well.
    2.3  Each facility component or system controlled through use of 
BMPs shall be examined for its NAF-waste minimization opportunities 
and its potential for causing a discharge of NAF to waters of the 
United States due to equipment failure, improper operation, natural 
phenomena (e.g., rain, snowfall).
    2.4  For each NAF wastestream controlled through BMPs where 
experience indicates a reasonable potential for equipment failure 
(e.g., a tank overflow or leakage), natural condition (e.g., 
precipitation), or other circumstances to result in NAF reaching 
surface waters, the BMP Plan shall include a prediction of the total 
quantity of NAF which could be discharged from the facility as a 
result of each condition or circumstance.

3.0  BMP Plan Requirements

    3.1  The BMP Plan may reflect requirements within the pollution 
prevention requirements required by the Minerals Management Service 
(see 30 CFR 250.300) or other Federal or State requirements and 
incorporate any part of such plans into the BMP Plan by reference.
    3.2  The operator shall certify that its BMP Plan is complete, 
on-site, and available upon request to EPA or the NPDES Permit 
controlling authority. This certification shall identify the NPDES 
permit number and be signed by an authorized representative of the 
operator. This certification shall be kept with the BMP Plan. For 
new or modified NPDES permits, the certification shall be made no 
later than the effective date of the new or modified permit. For 
existing NPDES permits, the certification shall be made within one 
year of permit issuance.
    3.3  The BMP Plan shall:
    3.3.1  Be documented in narrative form, and shall include any 
necessary plot plans, drawings or maps, and shall be developed in 
accordance with good engineering practices. At a minimum, the BMP 
Plan shall contain the planning, development and implementation, and 
evaluation/reevaluation components. Examples of these components are 
contained in ``Guidance Document for Developing Best Management 
Practices (BMP)'' (EPA 833-B-93-004, U.S. EPA, 1993).
    3.3.2  Include the following provisions concerning BMP Plan 
review.
    3.3.2.1  Be reviewed by permittee's drilling engineer and 
offshore installation manager (OIM) to ensure compliance with the 
BMP Plan purpose and objectives set forth in Section 2.0.
    3.3.2.2  Include a statement that the review has been completed 
and that the BMP Plan fulfills the BMP Plan purpose and objectives 
set forth in Section 2.0. This statement shall have dated signatures 
from the permittee's drilling engineer and offshore installation 
manager and any other individuals responsible for development and 
implementation of the BMP Plan.
    3.4  Address each component or system capable of generating or 
causing a release of significant amounts of NAF and identify 
specific preventative or remedial measures to be implemented.

4.0  BMP Plan Documentation

    4.1  The operator shall maintain a copy of the BMP Plan and 
related documentation (e.g., training certifications, summary of the 
monitoring results, records of NAF-equipment spills, repairs, and 
maintenance) at the facility and shall make the BMP Plan and related 
documentation available to EPA or the NPDES Permit controlling 
authority upon request.

5.0  BMP Plan Modification

    5.1  For those NAF wastestreams controlled through BMPs, the 
operator shall amend the BMP Plan whenever there is a change in the 
facility or in the operation of the facility which materially 
increases the generation of those NAF-wastes or their release or 
potential release to the receiving waters.
    5.2  At a minimum the BMP Plan shall be reviewed once every five 
years and amended within three months if warranted. Any such changes 
to the BMP Plan shall be consistent with the objectives and specific 
requirements listed in this addendum. All changes in the BMP Plan 
shall be reviewed by the permittee's drilling engineer and offshore 
installation manager.

[[Page 6914]]

    5.3  At any time, if the BMP Plan proves to be ineffective in 
achieving the general objective of preventing and minimizing the 
generation of NAF-wastes and their release and potential release to 
the receiving waters and/or the specific requirements in this 
addendum, the permit and/or the BMP Plan shall be subject to 
modification to incorporate revised BMP requirements.

6.0  Specific Pollution Prevention Requirements for NAF Discharges 
Associated with Cuttings

    6.1  The following specific pollution prevention activities are 
required in a BMP Plan when operators elect to control NAF 
discharges associated with cuttings by a set of BMPs.
    6.2  Establishing programs for identifying, documenting, and 
repairing malfunctioning NAF equipment, tracking NAF equipment 
repairs, and training personnel to report and evaluate 
malfunctioning NAF equipment.
    6.3  Establishing operating and maintenance procedures for each 
component in the solids control system in a manner consistent with 
the manufacturer's design criteria.
    6.4  Using the most applicable spacers, flushes, pills, and 
displacement techniques in order to minimize contamination of 
drilling fluids when changing from water-based drilling fluids to 
NAF and vice versa.
    6.5  A daily retort analysis shall be performed (in accordance 
with Appendix 7 to subpart A of Part 435) during the first 0.33 X 
feet drilled with NAF where X is the anticipated total feet to be 
drilled with NAF for that particular well. The retort analyses shall 
be documented in the well retort log. The operators shall use the 
calculation procedures detailed in Appendix 7 to subpart A of part 
435 (see Equations 1 through 8) to determine the arithmetic average 
(%BF<INF>well</INF>) of the retort analyses taken during the first 
0.33 X feet drilled with NAF.
    6.5.1  When the arithmetic average (%BF<INF>well</INF>) of the 
retort analyses taken during the first 0.33 X feet drilled with NAF 
is less than or equal to the base fluid retained on cuttings 
limitation or standard (see Secs. 435.13 and 435.15), retort 
monitoring of cuttings may cease for that particular well. The same 
BMPs and drilling fluid used during the first 0.33 X feet shall be 
used for all remaining NAF sections for that particular well.
    6.5.2  When the arithmetic average (%BF<INF>well</INF>) of the 
retort analyses taken during the first 0.33 X feet drilled with NAF 
is greater the base fluid retained on cuttings limitation or 
standard (see Secs. 435.13 and 435.15), retort monitoring shall 
continue for the following (second) 0.33 X feet drilled with NAF 
where X is the anticipated total feet to be drilled with NAF for 
that particular well. The retort analyses for the first and second 
0.33 X feet shall be documented in the well retort log.
    6.5.2.1  When the arithmetic average (%BF<INF>well</INF>) of the 
retort analyses taken during the first 0.66 X feet (i.e., retort 
analyses taken from first and second 0.33 X feet) drilled with NAF 
is less than or equal to the base fluid retained on cuttings 
limitation or standard (see Secs. 435.13 and 435.15), retort 
monitoring of cuttings may cease for that particular well. The same 
BMPs and drilling fluid used during the first 0.66 X feet shall be 
used for all remaining NAF sections for that particular well.
    6.5.2.2  When the arithmetic average (%BF<INF>well</INF>) of the 
retort analyses taken during the first 0.66 X feet (i.e., retort 
analyses taken from first and second 0.33 X feet) drilled with NAF 
is greater than the base fluid retained on cuttings limitation or 
standard (see Secs. 435.13 and 435.15), retort monitoring shall 
continue for all remaining NAF sections for that particular well. 
The retort analyses for all NAF sections shall be documented in the 
well retort log.
    6.5.3  When the arithmetic average (%BF<INF>well</INF>) of the 
retort analyses taken over all NAF sections for the entire well is 
greater that the base fluid retained on cuttings limitation or 
standard (see Secs. 435.13 and 435.15), the operator is in violation 
of the base fluid retained on cuttings limitation or standard and 
shall submit notification of these monitoring values in accordance 
with NPDES permit requirements. Additionally, the operator shall, as 
part of the BMP Plan, initiate a reevaluation and modification to 
the BMP Plan in conjunction with equipment vendors and/or industry 
specialists.
    6.5.4  The operator shall include retort monitoring data and 
dates of retort-monitored and non-retort-monitored NAF-cuttings 
discharges managed by BMPs in their NPDES permit reports.
    6.6  Establishing mud pit and equipment cleaning methods in such 
a way as to minimize the potential for building-up drill cuttings 
(including accumulated solids) in the active mud system and solids 
control equipment system. These cleaning methods shall include but 
are not limited to the following procedures.
    6.6.1  Ensuring proper operation and efficiency of mud pit 
agitation equipment.
    6.6.2  Using mud gun lines during mixing operations to provide 
agitation in dead spaces.
    6.6.3  Pumping drilling fluids off of drill cuttings (including 
accumulated solids) for use, recycle, or disposal before using wash 
water to dislodge solids.

Appendix 8 to Subpart A of Part 435--Reference C<INF>16</INF>-
C<INF>18</INF> Internal Olefin Drilling Fluid Formulation

    The reference C<INF>16</INF>-C<INF>18</INF> internal olefin 
drilling fluid used to determine the drilling fluid sediment 
toxicity ratio and compliance with the BAT sediment toxicity 
discharge limitation (see Sec. 435.13) and NSPS (see Sec. 435.15) 
shall be formulated to meet the specifications in Table 1 of this 
appendix.
    Drilling fluid sediment toxicity ratio = 4-day LC<INF>50</INF> 
of C<INF>16</INF>-C<INF>18</INF> internal olefin drilling fluid/4-
day LC<INF>50</INF> of drilling fluid removed from cuttings at the 
solids control equipment as determined by ASTM E1367-92 
[incorporated by reference and specified at Sec. 435.11(ee)] and 
supplemented with the sediment preparation procedure (Appendix 3 of 
subpart A of this part).

         Table 1.--Properties for Reference C<INF>16</INF>-C<INF>18</INF> IOs SBF Used in Discharge Sediment Toxicity Testing
----------------------------------------------------------------------------------------------------------------
                                                                                          Reference C<INF>16</INF>-C<INF>18</INF> IOs
Mud weight of SBF discharged with cuttings (pounds per gallon)   Reference C<INF>16</INF>-C<INF>18</INF> IOs    SBF synthetic to water
                                                                SBF (pounds per gallon)         ratio (%)
----------------------------------------------------------------------------------------------------------------
8.5-11........................................................                      9.0                    75/25
11-14.........................................................                     11.5                    80/20
>14...........................................................                     14.5                    85/15
================================================================================================================
Plastic Viscosity (PV), centipoise (cP).......................                    12-30
Yield Point (YP), pounds/100 sq. ft...........................                    10-20
10-second gel, pounds/100 sq. ft..............................                     8-15
10-minute gel, pounds/100 sq. ft..............................                    12-30
Electrical stability, V.......................................                     >300
----------------------------------------------------------------------------------------------------------------

Subpart D--Coastal Subcategory

    8. Section 435.41 is amended by revising paragraphs (b) through 
(ff) and by adding paragraphs (gg) through (ii) to read as follows:


Sec. 435.41  Special definitions.

* * * * *
    (b) Average of daily values for 30 consecutive days means the 
average of the daily values obtained during any 30 consecutive day 
period.
    (c) Base fluid means the continuous phase or suspending medium of a 
drilling fluid formulation.
    (d) Base fluid retained on cuttings as applied to BAT effluent 
limitations and NSPS refers to the American Petroleum Institute 
Recommended Practice 13B-2

[[Page 6915]]

supplemented with the specifications, sampling methods, and averaging 
method for retention values provided in Appendix 7 of subpart A of this 
part.
    (e) Biodegradation rate as applied to BAT effluent limitations and 
NSPS for drilling fluids and drill cuttings refers to the ISO 
11734:1995 method: ``Water quality--Evaluation of the `ultimate' 
anaerobic biodegradability of organic compounds in digested sludge--
Method by measurement of the biogas production (1995 edition)'' 
(Available from the American National Standards Institute, 11 West 42nd 
Street, 13th Floor, New York, NY 10036) supplemented with modifications 
in Appendix 4 of subpart A of this part.
    (f) Cook Inlet refers to coastal locations north of the line 
between Cape Douglas on the West and Port Chatham on the east.
    (g) Daily values as applied to produced water effluent limitations 
and NSPS means the daily measurements used to assess compliance with 
the maximum for any one day.
    (h) Deck drainage means any waste resulting from deck washings, 
spillage, rainwater, and runoff from gutters and drains including drip 
pans and work areas within facilities subject to this Subpart.
    (i) Development facility means any fixed or mobile structure 
subject to this Subpart that is engaged in the drilling of productive 
wells.
    (j) Dewatering effluent means wastewater from drilling fluids and 
drill cuttings dewatering activities (including but not limited to 
reserve pits or other tanks or vessels, and chemical or mechanical 
treatment occurring during the drilling solids separation/recycle/
disposal process).
    (k) Diesel oil refers to the grade of distillate fuel oil, as 
specified in the American Society for Testing and Materials Standard 
Specification for Diesel Fuel Oils D975-91, that is typically used as 
the continuous phase in conventional oil-based drilling fluids. This 
incorporation by reference was approved by the Director of the Federal 
Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies 
may be obtained from the American Society for Testing and Materials, 
1916 Race Street, Philadelphia, PA 19103. Copies may be inspected at 
the Office of the Federal Register, 800 North Capitol Street, NW., 
Suite 700, Washington, DC. A copy may also be inspected at EPA's Water 
Docket, 401 M Street SW., Washington, DC 20460.
    (l) Domestic waste means the materials discharged from sinks, 
showers, laundries, safety showers, eye-wash stations, hand-wash 
stations, fish cleaning stations, and galleys located within facilities 
subject to this Subpart.
    (m) Drill cuttings means the particles generated by drilling into 
subsurface geologic formations and carried out from the wellbore with 
the drilling fluid. Examples of drill cuttings include small pieces of 
rock varying in size and texture from fine silt to gravel. Drill 
cuttings are generally generated from solids control equipment and 
settle out and accumulate in quiescent areas in the solids control 
equipment or other equipment processing drilling fluid (i.e., 
accumulated solids).
    (1) Wet drill cuttings means the unaltered drill cuttings and 
adhering drilling fluid and formation oil carried out from the wellbore 
with the drilling fluid.
    (2) Dry drill cuttings means the residue remaining in the retort 
vessel after completing the retort procedure specified in Appendix 7 of 
subpart A of this part.
    (n) Drilling fluid means the circulating fluid (mud) used in the 
rotary drilling of wells to clean and condition the hole and to 
counterbalance formation pressure. Classes of drilling fluids are:
    (1) Water-based drilling fluid means the continuous phase and 
suspending medium for solids is a water-miscible fluid, regardless of 
the presence of oil.
    (2) Non-aqueous drilling fluid means the continuous phase and 
suspending medium for solids is a water-immiscible fluid, such as 
oleaginous materials (e.g., mineral oil, enhanced mineral oil, 
paraffinic oil, C<INF>16</INF>-C<INF>18</INF> internal olefins, and 
C<INF>8</INF>-C<INF>16</INF> fatty acid/2-ethylhexyl esters).
    (i) Oil-based means the continuous phase of the drilling fluid 
consists of diesel oil, mineral oil, or some other oil, but contains no 
synthetic material or enhanced mineral oil.
    (ii) Enhanced mineral oil-based means the continuous phase of the 
drilling fluid is enhanced mineral oil.
    (iii) Synthetic-based means the continuous phase of the drilling 
fluid is a synthetic material or a combination of synthetic materials.
    (o) Enhanced mineral oil as applied to enhanced mineral oil-based 
drilling fluid means a petroleum distillate which has been highly 
purified and is distinguished from diesel oil and conventional mineral 
oil in having a lower polycyclic aromatic hydrocarbon (PAH) content. 
Typically, conventional mineral oils have a PAH content on the order of 
0.35 weight percent expressed as phenanthrene, whereas enhanced mineral 
oils typically have a PAH content of 0.001 or lower weight percent PAH 
expressed as phenanthrene.
    (p) Exploratory facility means any fixed or mobile structure 
subject to this Subpart that is engaged in the drilling of wells to 
determine the nature of potential hydrocarbon reservoirs.
    (q) Formation oil means the oil from a producing formation which is 
detected in the drilling fluid, as determined by the GC/MS compliance 
assurance method specified in Appendix 5 of subpart A of this part when 
the drilling fluid is analyzed before being shipped offshore, and as 
determined by the RPE method specified in Appendix 6 of subpart A of 
this part when the drilling fluid is analyzed at the offshore point of 
discharge. Detection of formation oil by the RPE method may be 
confirmed by the GC/MS compliance assurance method, and the results of 
the GC/MS compliance assurance method shall supercede those of the RPE 
method.
    (r) Garbage means all kinds of victual, domestic, and operational 
waste, excluding fresh fish and parts thereof, generated during the 
normal operation of coastal oil and gas facility and liable to be 
disposed of continuously or periodically, except dishwater, graywater, 
and those substances that are defined or listed in other Annexes to 
MARPOL 73/78. A copy of MARPOL may be inspected at EPA's Water Docket; 
401 M Street SW., Washington DC 20460.
    (s) M9IM means those offshore facilities continuously manned by 
nine (9) or fewer persons or only intermittently manned by any number 
of persons.
    (t) M10 means those offshore facilities continuously manned by ten 
(10) or more persons.
    (u) Maximum as applied to BAT effluent limitations and NSPS for 
drilling fluids and drill cuttings means the maximum concentration 
allowed as measured in any single sample of the barite for 
determination of cadmium and mercury content.
    (v) Maximum for any one day as applied to BPT, BCT and BAT effluent 
limitations and NSPS for oil and grease in produced water means the 
maximum concentration allowed as measured by the average of four grab 
samples collected over a 24-hour period that are analyzed separately. 
Alternatively, for BAT and NSPS the maximum concentration allowed may 
be determined on the basis of physical composition of the four grab 
samples prior to a single analysis.
    (w) Minimum as applied to BAT effluent limitations and NSPS for 
drilling fluids and drill cuttings means the minimum 96-hour 
LC<INF>50</INF> value allowed as measured in any single sample of the 
discharged waste stream.

[[Page 6916]]

Minimum as applied to BPT and BCT effluent limitations and NSPS for 
sanitary wastes means the minimum concentration value allowed as 
measured in any single sample of the discharged waste stream.
    (x)(1) New source means any facility or activity of this 
subcategory that meets the definition of ``new source'' under 40 CFR 
122.2 and meets the criteria for determination of new sources under 40 
CFR 122.29(b) applied consistently with all of the following 
definitions:
    (i) Water area as used in ``site'' in 40 CFR 122.29 and 122.2 means 
the water area and water body floor beneath any exploratory, 
development, or production facility where such facility is conducting 
its exploratory, development or production activities.
    (ii) Significant site preparation work as used in 40 CFR 122.29 
means the process of surveying, clearing or preparing an area of the 
water body floor for the purpose of constructing or placing a 
development or production facility on or over the site.
    (2) ``New Source'' does not include facilities covered by an 
existing NPDES permit immediately prior to the effective date of these 
guidelines pending EPA issuance of a new source NPDES permit.
    (y) No discharge of free oil means that waste streams may not be 
discharged that contain free oil as evidenced by the monitoring method 
specified for that particular stream, e.g., deck drainage or 
miscellaneous discharges cannot be discharged when they would cause a 
film or sheen upon or discoloration of the surface of the receiving 
water; drilling fluids or cuttings may not be discharged when they fail 
the static sheen test defined in Appendix 1 of subpart A of this part.
    (z) Parameters that are regulated in this subpart and listed with 
approved methods of analysis in Table 1B at 40 CFR 136.3 are defined as 
follows:
    (1) Cadmium means total cadmium.
    (2) Chlorine means total residual chlorine.
    (3) Mercury means total mercury.
    (4) Oil and Grease means total recoverable oil and grease.
    (aa) Produced sand means the slurried particles used in hydraulic 
fracturing, the accumulated formation sands and scales particles 
generated during production. Produced sand also includes desander 
discharge from the produced water waste stream, and blowdown of the 
water phase from the produced water treating system.
    (bb) Produced water means the water (brine) brought up from the 
hydrocarbon-bearing strata during the extraction of oil and gas, and 
can include formation water, injection water, and any chemicals added 
downhole or during the oil/water separation process.
    (cc) Production facility means any fixed or mobile structure 
subject to this subpart that is either engaged in well completion or 
used for active recovery of hydrocarbons from producing formations. It 
includes facilities that are engaged in hydrocarbon fluids separation 
even if located separately from wellheads.
    (dd) Sanitary waste means the human body waste discharged from 
toilets and urinals located within facilities subject to this subpart.
    (ee) SPP toxicity as applied to BAT effluent limitations and NSPS 
for drilling fluids and drill cuttings refers to the bioassay test 
procedure presented in Appendix 2 of subpart A of this part.
    (ff) Static sheen test means the standard test procedure that has 
been developed for this industrial subcategory for the purpose of 
demonstrating compliance with the requirement of no discharge of free 
oil. The methodology for performing the static sheen test is presented 
in Appendix 1 of subpart A of this part.
    (gg) Stock barite means the barite that was used to formulate a 
drilling fluid.
    (hh) Synthetic material as applied to synthetic-based drilling 
fluid means material produced by the reaction of specific purified 
chemical feedstock, as opposed to the traditional base fluids such as 
diesel and mineral oil which are derived from crude oil solely through 
physical separation processes. Physical separation processes include 
fractionation and distillation and/or minor chemical reactions such as 
cracking and hydro processing. Since they are synthesized by the 
reaction of purified compounds, synthetic materials suitable for use in 
drilling fluids are typically free of polycyclic aromatic hydrocarbons 
(PAH's) but are sometimes found to contain levels of PAH up to 0.001 
weight percent PAH expressed as phenanthrene. Internal olefins and 
vegetable esters are two examples of synthetic materials suitable for 
use by the oil and gas extraction industry in formulating drilling 
fluids. Internal olefins are synthesized from the isomerization of 
purified straight-chain (linear) hydrocarbons such as C<INF>16</INF>-
C<INF>18</INF> linear alpha olefins. C<INF>16</INF>-C<INF>18</INF> 
linear alpha olefins are unsaturated hydrocarbons with the carbon to 
carbon double bond in the terminal position. Internal olefins are 
typically formed from heating linear alpha olefins with a catalyst. The 
feed material for synthetic linear alpha olefins is typically purified 
ethylene. Vegetable esters are synthesized from the acid-catalyzed 
esterification of vegetable fatty acids with various alcohols. EPA 
listed these two branches of synthetic fluid base materials to provide 
examples, and EPA does not mean to exclude other synthetic materials 
that are either in current use or may be used in the future. A 
synthetic-based drilling fluid may include a combination of synthetic 
materials.
    (ii) Well completion fluids means salt solutions, weighted brines, 
polymers, and various additives used to prevent damage to the well bore 
during operations which prepare the drilled well for hydrocarbon 
production.
    (jj) Well treatment fluids means any fluid used to restore or 
improve productivity by chemically or physically altering hydrocarbon-
bearing strata after a well has been drilled.
    (kk) Workover fluids means salt solutions, weighted brines, 
polymers, or other specialty additives used in a producing well to 
allow for maintenance, repair or abandonment procedures.
    (ll) 96-hour LC<INF>50</INF> means the concentration (parts per 
million) or percent of the suspended particulate phase (SPP) from a 
sample that is lethal to 50 percent of the test organisms exposed to 
that concentration of the SPP after 96 hours of constant exposure.

    9. In Sec. 435.42 the table is amended by removing the entries 
``Drilling fluids'' and ``Drill cuttings'' and by adding new entries 
(after ``Deck drainage'') for ``Water based'' and ``Non-aqueous'' to 
read as follows:


Sec. 435.42  Effluent limitations guidelines representing the degree of 
effluent reduction attainable by the application of the best 
practicable control technology currently available (BPT).

* * * * *

[[Page 6917]]



                                    BPT Effluent Limitations--Oil and Grease
                                            [In milligrams per liter]
----------------------------------------------------------------------------------------------------------------
                                                                 Average of values for 30
   Pollutant parameter waste source      Maximum for any 1 day    consecutive days shall     Residual chlorine
                                                                        not exceed         minimum for any 1 day
----------------------------------------------------------------------------------------------------------------
 
       *                  *                   *                   *                  *                   *
                                                          *
Water-based:
    Drilling fluids..................  ( \1\)..................  ( \1\)..................  NA
    Drill Cuttings...................  ( \1\)..................  ( \1\)..................  NA
Non-aqueous:
    Drilling fluids..................  No discharge............  No discharge............  NA
    Drill Cuttings...................  ( \1\)..................  ( \1\)..................  NA
 
       *                  *                   *                   *                  *                   *
                                                       *
----------------------------------------------------------------------------------------------------------------
\1\ No discharge of free oil.

* * * * *
    10. In Sec. 435.43 the table is amended by revising entry (B) under 
``Drilling fluids, drill cuttings, and dewatering effluent'' and by 
revising footnote 4 and adding footnote 5 to read as follows:


Sec. 435.43  Effluent limitations guidelines representing the degree of 
effluent reduction attainable by the application of the best available 
technology economically achievable (BAT).

* * * * *

                        BAT Effluent Limitations
------------------------------------------------------------------------
                                    Pollutant           BAT effluent
         Waste source               parameter            limitation
------------------------------------------------------------------------
 
      *                  *                   *                   *
                  *                   *                   *
Drilling fluids, Drill
 cuttings, and Dewatering
 effluent: \1\
 
      *                  *                   *                   *
                  *                   *                   *
(B) Cook Inlet:
    Water-based drilling        SPP Toxicity.....  Minimum 96-hour LC<INF>50</INF>
     fluids, drill cuttings,                        of the SPP Toxicity
     and dewatering effluent.                       Test <SUP>4</SUP> shall be 3%
                                                    by volume.
                                Free oil.........  No discharge.\2\
                                Diesel oil.......  No discharge.
                                Mercury..........  1 mg/kg dry weight
                                                    maximum in the stock
                                                    barite.
                                Cadmium..........  3 mg/kg dry weight
                                                    maximum in the stock
                                                    barite.
    Non-aqueous drilling          ...............  No discharge.
     fluids and dewatering
     effluent.
    Drill cuttings associated     ...............  No discharge.\5\
     with non-aqueous drilling
     fluids.
 
      *                  *                   *                   *
                 *                   *                   *
------------------------------------------------------------------------
\1\ BAT limitations for dewatering effluent are applicable
  prospectively. BAT limitations in this rule are not applicable to
  discharges of dewatering effluent from reserve pits which as of the
  effective date of this rule no longer receive drilling fluids and
  drill cuttings. Limitations on such discharges shall be determined by
  the NPDES permit issuing authority.
\2\ As determined by the static sheen test (see Appendix 1 of Subpart A
  of this part).
*                  *                   *                   *
      *                   *                   *
\4\ As determined by the suspended particulate phase (SPP) toxicity test
  (see Appendix 2 of Subpart A of this part).
\5\ When Cook Inlet operators cannot comply with this no discharge
  requirement due to technical limitations (see Appendix 1 of Subpart D
  of this part), Cook Inlet operators shall meet the same stock
  limitations (C<INF>16</INF>-C<INF>18</INF> internal olefin) and discharge limitations for
  drill cuttings associated with non-aqueous drilling fluids for
  operators in Offshore waters (see Sec.  435.13) in order to discharge
  drill cuttings associated with non-aqueous drilling fluids.


    11. In Sec. 435.44 the table is amended by revising the entry for 
``Cook Inlet'' under the entry for ``Drilling fluids and drill cuttings 
and dewatering effluent'' to read as follows:


Sec. 435.44  Effluent limitations guidelines representing the degree of 
effluent reduction attainable by the application of the best 
conventional pollutant control technology (BCT).

* * * * *

[[Page 6918]]



                        BCT Effluent Limitations
------------------------------------------------------------------------
                                  Pollutant
         Waste source             parameter      BCT effluent limitation
------------------------------------------------------------------------
 
      *                  *                   *                   *
                  *                   *                   *
Drilling fluids, Drill
 cuttings, and Dewatering
 effluent: \1\
 
      *                  *                   *                   *
                  *                   *                   *
Cook Inlet:
    Water-based drilling       Free Oil.......  No discharge.\2\
     fluids, drill cuttings,
     and dewatering effluent.
    Non-aqueous drilling         .............  No discharge.
     fluids and dewatering
     effluent.
    Drill cuttings associated  Free Oil.......  No discharge.\2\
     with non-aqueous
     drilling fluids.
------------------------------------------------------------------------
\1\ BCT limitations for dewatering effluent are applicable
  prospectively. BCT limitations in this rule are not applicable to
  discharges of dewatering effluent from reserve pits which as of the
  effective date of this rule no longer receive drilling fluids and
  drill cuttings. Limitations on such discharges shall be determined by
  the NPDES permit issuing authority.
\2\ As determined by the static sheen test (see Appendix 1 of Subpart A
  of this part).

* * * * *

    12. In Sec. 435.45 the table is amended by revising entry (B) under 
``Drilling fluids, drill cuttings, and dewatering effluent'' and by 
revising footnote 4 and adding footnote 5 to read as follows:


Sec. 435.45  Standards of performance for new sources (NSPS).

* * * * *

                 New Source Performance Standards (NSPS)
------------------------------------------------------------------------
                                    Pollutant
         Waste Source               parameter               NSPS
------------------------------------------------------------------------
 
*                  *                  *                  *
         *                  *                  *
Drilling fluids, Drill
 cuttings, and Dewatering
 effluent: \1\
 
*                  *                  *                  *
         *                  *                  *
(B) Cook Inlet:
    Water-based drilling        SPP Toxicity.....  Minimum 96-hour LC<INF>50</INF>
     fluids, drill cuttings,                        of the SPP Toxicity
     and dewatering effluent.                       Test \4\ shall be 3%
                                                    by volume.
                                Free oil.........  No discharge.\2\
                                Diesel oil.......  No discharge.
                                Mercury..........  1 mg/kg dry weight
                                                    maximum in the stock
                                                    barite.
                                Cadmium..........  3 mg/kg dry weight
                                                    maximum in the stock
                                                    barite.
    Non-aqueous drilling          ...............  No discharge.
     fluids and dewatering
     effluent.
    Drill cuttings associated     ...............  No discharge.\5\
     with non-aqueous drilling
     fluids.
 
*                  *                  *                  *
           *                  *                  *
------------------------------------------------------------------------
\1\ NSPS for dewatering effluent are applicable prospectively. NSPS in
  this rule are not applicable to discharges of dewatering effluent from
  reserve pits which as of the effective date of this rule no longer
  receive drilling fluids and drill cuttings. Limitations on such
  discharges shall be determined by the NPDES permit issuing authority.
\2\ As determined by the static sheen test (see Appendix 1 of subpart A
  of this part).
*                  *                  *                  *
     *                  *              *
\4\ As determined by the suspended particulate phase (SPP) toxicity test
  (see Appendix 2 of subpart A of this part).
\5\ When Cook Inlet operators cannot comply with this no discharge
  requirement due to technical limitations (see Appendix 1 of subpart D
  of this part), Cook Inlet operators shall meet the same stock
  limitations (C<INF>16</INF>-C<INF>18</INF> internal olefin) and discharge limitations for
  drill cuttings associated with non-aqueous drilling fluids for
  operators in Offshore waters (see Sec.  435.15) in order to discharge
  drill cuttings associated with non-aqueous drilling fluids.


    13. Subpart D is amended by adding Appendix 1 as follows:

Appendix 1 to Subpart D of Part 435--Procedure for Determining When 
Coastal Cook Inlet Operators Qualify for an Exemption from the Zero 
Discharge Requirement for EMO-Cuttings and SBF-Cuttings in Coastal Cook 
Inlet, Alaska

1.0  Scope and Application

    This appendix is to be used to determine whether a Cook Inlet, 
Alaska, operator in Coastal waters (Coastal Cook Inlet operator) 
qualifies for the exemption to the zero discharge requirement 
established by 40 CFR 435.43 and 435.45 for drill cuttings 
associated with the following non-aqueous drilling fluids: enhanced 
mineral oil based drilling fluids (EMO-cuttings) and synthetic-based 
drilling fluids (SBF-cuttings). Coastal Cook Inlet operators are 
prohibited from discharging oil-based drilling fluids. This appendix 
is intended to define those situations under which technical 
limitations

[[Page 6919]]

preclude Coastal Cook Inlet operators from complying with the zero 
discharge requirement for EMO-cuttings and SBF-cuttings. Coastal 
Cook Inlet operators that qualify for this exemption may be 
authorized to discharge EMO-cuttings and SBF-cuttings subject to the 
limitations applicable to operators in Offshore waters (see subpart 
A of this part).

2.0  Method

    2.1  Any Coastal Cook Inlet operator must achieve the zero 
discharge limit for EMO-cuttings and SBF-cuttings unless it 
successfully demonstrates that technical limitations prevent it from 
being able to dispose of its EMO-cuttings or SBF-cuttings through 
on-site annular disposal, injection into a Class II underground 
injection control (UIC) well, or onshore land application.
    2.2  To successfully demonstrate that technical limitations 
prevent it from being able to dispose of its EMO-cuttings or SBF-
cuttings through on-site annular disposal, a Coastal Cook Inlet 
operator must show that it has been unable to establish formation 
injection in nearby wells that were initially considered for annular 
or dedicated disposal of EMO-cuttings or SBF-cuttings or prove to 
the satisfaction of the Alaska Oil and Gas Conservation Commission 
(AOGCC) that the EMO-cuttings or SBF-cuttings will be confined to 
the formation disposal interval. This demonstration must include:
    a. Documentation, including engineering analysis, that shows (1) 
an inability to establish formation injection (e.g., formation is 
too tight), (2) an inability to confine EMO-cuttings or SBF-cuttings 
in disposal formation (e.g., no confining zone or adequate barrier 
to confine wastes in formation), or (3) the occurrence of high risk 
emergency (e.g., mechanical failure of well, loss of ability to 
inject that risks loss of well which would cause significant 
economic harm or create a substantial risk to safety); and
    b. A risk analysis of alternative disposal options, including 
environmental assessment, human health and safety, and economic 
impact, that shows discharge as the lowest risk option.
    2.3  To successfully demonstrate that technical limitations 
prevent it from being able to dispose of its EMO-cuttings or SBF-
cuttings through injection into a Class II UIC well, a Coastal Cook 
Inlet operator must show that it has been unable to establish 
injection into a Class II UIC well or prove to the satisfaction of 
the Alaska Oil and Gas Conservation Commission (AOGCC) that the EMO-
cuttings or SBF-cuttings will be confined to the formation disposal 
interval. This demonstration must include:
    a. Documentation, including engineering analysis, that shows the 
inability to confine EMO-cuttings or SBF-cuttings in a Class II UIC 
well (e.g., no confining zone or adequate barrier to confine wastes 
in formation);
    b. Documentation demonstrating that no Class II UIC well is 
accessible (e.g., operator does not own, competitor will not allow 
injection); and
    c. A risk analysis of alternative disposal option, including 
environmental assessment, human health and safety, and economic 
impact, that shows discharge as the lowest risk option.
    2.4  To successfully demonstrate that technical limitations 
prevent it from being able to dispose of its EMO-cuttings or SBF-
cuttings through land application, a Coastal Cook Inlet operator 
must show that it has been unable to handle drilling waste or 
dispose of EMO-cuttings or SBF-cuttings at an appropriate land 
disposal site. This demonstration must include:
    a. Documentation of site restrictions that preclude land 
application (e.g., no land disposal sites available);
    b. Documentation of the platform's lack of capacity for adequate 
storage of EMO-cuttings or SBF-cuttings (e.g., limited storage or 
room for cuttings transfer); or
    c. Documentation of inability to transfer EMO-cuttings or SBF-
cuttings from platform to land for disposal (e.g., extremely low 
tides, high wave action).

3.0  Procedure

    3.1  Except as described in Section 3.2 of this appendix, a 
Coastal Cook Inlet operator believing that it qualifies for the 
exemption to the zero discharge requirement for EMO-cuttings or SBF-
cuttings must apply for and obtain an individual NPDES permit prior 
to discharging EMO-cuttings or SBF-cuttings to waters of the United 
States.
    3.2  Discharges occurring as the result a high risk emergency 
(e.g., mechanical failure of well, loss of ability to inject that 
risks loss of well which would cause significant economic harm or 
safety) may be authorized by a general NPDES permit provided that:
    a. The Coastal Cook Inlet operator satisfactorily demonstrates 
to EPA Region 10 the fulfillment of the other exemption requirements 
described in Section 2.0 of this appendix, or
    b. The general permit allows for high risk emergency discharges 
and provides Reporting Requirements to EPA Region 10 immediately 
upon commencing discharge.
[FR Doc. 01-361 Filed 1-19-01; 8:45 am]
BILLING CODE 6560-50-U


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