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

ENVIRONMENTAL PROTECTION

AGENCY

40 CFR Parts 9 and 435

[FRL–6929–8]

RIN 2040–AD14

Effluent Limitations Guidelines and

New Source Performance Standards

for the Oil and Gas Extraction Point

Source Category; OMB Approval

Under the Paperwork Reduction Act:

Technical Amendment

AGENCY: Environmental Protection

Agency (EPA).

ACTION: Final Rule; technical

amendment.

SUMMARY: EPA is publishing final

regulations establishing technologybased effluent limitations guidelines

and standards for the discharge of

synthetic-based drilling fluids (SBFs)

and other non-aqueous drilling fluids

from oil and gas drilling operations into

waters of the United States. Oil and gas

extraction facilities generate cuttings

wastes from drilling operations. This

regulation applies to existing and new

sources that perform oil and natural gas

extraction drilling in certain offshore

and coastal waters. The final rule allows

a controlled discharge of SBF-cuttings

anywhere offshore of Alaska and

offshore of the rest of the United States

beyond three miles from shore. This

regulation prohibits discharge of such

fluids in coastal Cook Inlet, Alaska,

unless certain findings are made by the

permit authority. The final rule

prohibits the discharge of SBFs not

associated with drill cuttings into all

waters of the United States.

Compliance with this rule is

estimated to reduce the annual

discharge of cuttings by 118 million

pounds per year for new and existing

sources. This rule will also lead to a

decrease of 2,927 tons of air emissions

and 200,817 barrels of oil equivalent

(BOE) per year for new and existing

sources. EPA estimates that the rule will

result in annual savings of $48.9 million

and no adverse economic impacts to the

industry as a whole. EPA also

incorporated Best Management Practices

(BMPs) into the final rule to provide

industry with additional flexibility in

meeting today’s final rule. In

compliance with the Paperwork

Reduction Act (PRA), this action also

makes a technical amendment to the

table in part 9 that lists the Office of

Management and Budget (OMB) control

numbers issued under the PRA for

today’s final rule. EPA is amending part

9 to include the OMB control number

for the information collection

requirements associated with the BMPs

promulgated in today’s final rule.

DATES: This regulation shall become

effective February 21, 2001. For judicial

review purposes, this final rule is

promulgated as of 1 p.m. Eastern Time

on February 5, 2001, as provided in 40

CFR 23.2. The incorporation by

reference of certain publications listed

in the regulations is approved by the

Director of the Office of Federal Register

as of February 21, 2001.

ADDRESSES: The public record is

available for review in the EPA Water

Docket, East Tower Basement, Room

EB–57, 401 M St. SW., Washington, DC

20460. The public record for this rule

has been established under docket

number W–98–26, and includes

supporting documentation, but does not

include any information claimed as

Confidential Business Information (CBI).

The record is available for inspection

from 9 a.m. to 4 p.m., Monday through

Friday, excluding legal holidays. For

access to docket materials, please call

(202) 260–3027 to schedule an

appointment.

FOR FURTHER INFORMATION CONTACT: For

additional technical information contact

Mr. Carey A. Johnston at (202) 260–7186

or send E-mail to:

johnston.carey@epa.gov. For additional

economic information contact Mr. James

Covington at (202) 260–5132 or send Email to: covington.james@epa.gov.

SUPPLEMENTARY INFORMATION:

Regulated Entities

Entities potentially regulated by this

action include:

Category Examples of regulated entities

Industry ................................. Facilities engaged in the drilling of wells in the oil and gas industry in areas defined as ‘‘coastal’’ or ‘‘offshore’’

and discharging in geographic areas where drilling wastes are allowed for discharge (anywhere offshore of

Alaska and offshore of the rest of the United States beyond three miles from shore, and the coastal waters of

Cook Inlet, Alaska). Includes certain facilities covered under Standard Industrial Classification code 13 and

North American Industrial Classification System codes 211111 and 213111.

This table is not intended to be

exhaustive, but rather provides a guide

for readers regarding entities likely to be

regulated by this action. This table lists

the types of entities that EPA is now

aware could potentially be regulated by

this action. Other types of entities not

listed in the table could also be

regulated. To determine whether your

facility is regulated by this action, you

should carefully examine the

applicability criteria in 40 CFR part 435

(see §§ 435.10 and 435.40). If you have

questions regarding the applicability of

this action to a particular entity, consult

the person listed for technical

information in the preceding FOR

FURTHER INFORMATION CONTACT section.

Compliance Dates

Deadlines for compliance with Best

Practicable Control Technology

Currently Available (BPT), Best

Conventional Pollutant Control

Technology (BCT), and Best Available

Technology Economically Achievable

(BAT) are established in National

Pollutant Discharge Elimination System

(NPDES) permits. A new source must

comply with New Source Performance

Standards (NSPS) on the date the new

source commences discharging.

Technical Amendments to Part 9

EPA is amending the table of

currently approved information

collection request (ICR) control numbers

issued by OMB for various regulations.

The amendment updates the table to list

those information collection

requirements promulgated under

today’s final rule. The affected

regulations are codified at 40 CFR part

9. EPA will continue to present OMB

control numbers in a consolidated table

format to be codified in 40 CFR part 9

of the Agency’s regulations, and in each

CFR volume containing EPA

regulations. The table lists CFR citations

with reporting, recordkeeping, or other

information collection requirements,

and the current OMB control numbers.

This listing of the OMB control numbers

and their subsequent codification in the

CFR satisfies the requirements of the

Paperwork Reduction Act (44 U.S.C.

3501 et seq.) and OMB’s implementing

regulations at 5 CFR part 1320.

This ICR was previously subject to

public notice and comment prior to

OMB approval. Due to the technical

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

6852 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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 ‘‘costreasonableness’’ 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 (BOD5),

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).

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

6854 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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 OBFwaste 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 ultradeep 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

Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations 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 SBFcuttings 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 SBFcuttings discharges in Offshore waters.

Criteria for establishing when operators

cannot achieve zero discharge are

established in the final regulation. SBFcuttings 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

6856 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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 SBFcuttings 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 reinjection 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 shallowwater 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

Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations 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 SBFcuttings 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 WBFdrilling 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., BaSO4)

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-perstructure 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 121⁄4

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,

6858 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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 sidescanning 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 SBFcuttings 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 SBFcuttings 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 reinjected 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 recalculate 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

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

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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

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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 reinjection (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 reinjection (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 casespecific 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 oilbased 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 SBFcuttings 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

6862 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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) Shallowwater development (SWD); (2) shallowwater 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.

Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations 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. Ultrafines are generally classified as being

less than 5 microns (10–6 meters) in

length and solids control equipment

generally cannot remove these ultrafines. 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 (BaSO4),

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 nonconventional 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

6864 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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 nonconventional 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) nonconventional 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, C12–C14 vegetable esters

of 2-hexanol and palm kernel oil, ‘‘low

viscosity’’ C8 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, C12–C14 vegetable

esters of 2-hexanol and palm kernel oil,

‘‘low viscosity’’ C8 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 Kow 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 (Kow) is used

as a surrogate for estimating lipid/water

partitioning). Moreover, hydrophobic

chemicals (e.g., C16–C18 internal olefins,

various poly alpha olefins, and C18 nparaffins) with a log Kow 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

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

aluminum and tin. A complete SBF

formulation also includes nonconventional pollutants found in the

SBF base fluids (e.g., enhanced mineral

oils, internal olefins, linear alpha

olefins, poly alpha olefins, paraffinic

oils, C12–C14 vegetable esters of 2-

hexanol and palm kernel oil, ‘‘low

viscosity’’ C8 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 nonconventional pollutant parameter and as

an indicator for toxic pollutants in

SBFs. As originally proposed in

February 1999 (64 FR 5491) and restated 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 SBFcuttings 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,

6866 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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 LC50 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 (‘‘SBFcuttings’’). 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.

Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations 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 SBFcuttings 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 SBFcuttings as the minimum 96-hour LC50

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 SBFcuttings 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 SBFcuttings 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 C16–C18 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

6868 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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 SBFcuttings 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 SBFcuttings 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

Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations 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 SBFcuttings 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 reinjection 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 SBFcuttings, 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 SBFcuttings 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, C12–C14 vegetable esters

of 2-hexanol and palm kernel oil, and

‘‘low viscosity’’ C8 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 C16 and C18

alkenes; (2) linear alpha olefin (LAO)

refers to a series of isomeric forms of C14

and C16 monoenes; (3) poly alpha olefin

(PAO) refers to a mix mainly comprised

of a hydrogenated decene dimer C20H62

(95%), with lesser amounts of C30H62

(4.8%) and C10H22 (0.2%); (4) vegetable

ester refers to a monoester of 2-

ethylhexanol and saturated fatty acids

with chain lengths in the range C8–C16;

and (5) ‘‘low viscosity’’ ester refers to an

ester of natural or synthetic C8 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 Kow

<3 to 3.5 and log Kow> 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 C16–C18 IO. EPA

also considered subcategorizing the

final rule to determine when vegetable

esters are not practical and when C16–

C18 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

6870 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

include: (1) High viscosity compared

with other IO SBFs at all temperatures,

with an increasing difference as

temperature decreases, leading to lower

rates of penetration in wells and greater

probability of losses due to higher

equivalent circulating densities; (2) high

gel strength in risers that develops when

a vegetable ester-based SBF is not

circulated; (3) a high temperature

stability limit ranging from about 225 °F

to perhaps 320 °F—the exact value

depends on the detailed chemistry of

the vegetable ester (i.e., the acid, the

alcohol) and the drilling fluid

chemistry; (4) reduction of the thermal

stability limit through hydrolysis when

vegetable esters are in contact with

highly basic materials (e.g., lime, green

cement) at elevated temperatures; and

(5) less tolerance of the muds to

contamination by seawater, cement, and

drill solids than is observed for IO–SBFs

(Docket No. W–98–26: Record No.

IV.A.a.3, Attachment A2—‘‘Limitations

of Esters’; Record No. IV.A.a.13,

Attachments Ester-51, 52, 53, 54, 56).

EPA also rejected the option of

subcategorizing the use of esters to

define drilling conditions when only

esters could be allowed for a controlled

discharge. EPA could not establish a

‘‘bright line’’ rationale to define the

situation where only esters should be

the benchmark fluid (i.e., only esters

would be allowed for a controlled

discharge). EPA considered many of the

engineering factors used for selection of

a drilling fluid (e.g., rig size and

equipment; formation characteristics;

water depth and environment; lubricity,

rheological, and thixotropic

requirements) and determined that this

type of sub-categorization was not

possible. EPA, however, is encouraging

the use of esters by promulgating a

higher ROC limitation and standard

when esters are used.

EPA also considered basing sediment

toxicity and biodegradation stock

limitations and standards on low

viscosity esters. Comments to the April

2000 NODA state that laboratory

analyses, which were designed to

simulate GOM conditions to which a

fluid may be exposed, indicate that low

viscosity esters have the following

technical properties: (1) Similar or

better viscosity than C16–C18 IOs; (2) can

be used to formulate stable low viscosity

ester-based SBFs up to 300 °F; (3) can

be used to formulate low viscosity esterbased 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 C16–C18 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 C16–C18 IOs.

Alternatively, this limitation could be

expressed in terms of a ‘‘sediment

toxicity ratio’’ which is defined as 10-

day LC50 of C16–C18 internal olefins

divided by the 10-day LC50 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

Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations 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 C16–C18 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 SBFcuttings: (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 C16–C18

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 C16–C18

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 esterbased 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 esterbased 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

6872 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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 esterbased 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 SBFcuttings 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

Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations 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, HighG 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 × 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 × 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 × 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 × 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 C16–C18 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

6874 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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 SBFcuttings 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 SBFcuttings 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 SBFcuttings 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 nonconventional pollutant parameter and as

an indicator for other pollutants in the

SBF discharged with cuttings. Some of

the toxic, priority, and nonconventional 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, C12–C14 vegetable esters

of 2-hexanol and palm kernel oil, ‘‘low

viscosity’’ C8 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 SBFcuttings using SBFs as toxic or less

toxic, but not more toxic, than C16–C18

Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations 6875

IOs SBFs. Alternatively, this limitation

could be expressed in terms of a ‘‘SBF

sediment toxicity ratio’’ which is

defined as 96-hour LC50 of C16–C18

internal olefins SBF divided by the 96-

hour LC50 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 C16–C18 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 C16–C18 IOS SBF USED IN DISCHARGE SEDIMENT TOXICITY TESTING

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

SBF (pounds per gallon)

Reference C16–C18 ISOs

SBF synthetic to water

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 SBFcuttings 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.

6876 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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 SBFcuttings (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 SBFcuttings (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

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

6878 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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6880 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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

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

6882 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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

[In pounds/year]

Technology basis

SBF pollutant loadings

(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% retention of SBF on cuttings ............................................................... (2,604,704)

BAT/NSPS Option 2: Discharge with 3.82% retention of SBF on cuttings ............................................................... (3,123,322)

BAT/NSPS Option 3: Zero Discharge of SBF-wastes via land disposal or onsite injection ..................................... (9,921,126)

NOTE: EPA estimates the following GOM WBF/OBF/SBF new sources: Baseline—38/2/20; BAT/NSPS Option 1 & 2—35/1/24; and BAT/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,

6884 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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 NonWater 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 esterbased 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 esterbased 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

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

Technology basis

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

Gulf of MexicoOffshore

California

Cook Inlet,

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 disposal or onsite

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

aAnnual 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

Technology basis

Energy impacts: Reductions (increases)a fuel use

(BOE/yr)

BAT/NSPS Option 1: Discharge with LTA of 4.03% SBF ROC ....................................................................................... 6330

BAT/NSPS Option 2: Discharge with LTA of 3.82% SBF ROC ....................................................................................... 5693

BAT/NSPS Option 3: Zero Discharge of SBF-wastes via land disposal or onsite injection ............................................. (18,067)

aAnnual 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

Technology basis

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

Gulf of

Mexico

Offshore

California

Cook Inlet,

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 disposal or onsite

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

aAnnual 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).

6886 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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

Technology basis

Annual air

emissions

reduction

(increases) a

(tons/yr)

BAT/NSPS Option 1: Discharge with LTA of 4.03% SBF ROC ............................................................................................................. (136)

BAT/NSPS Option 2: Discharge with LTA of 3.82% SBF ROC ............................................................................................................. (145)

BAT/NSPS Option 3: Zero Discharge of SBF-wastes via land disposal or onsite injection ................................................................... (528)

aAnnual 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 ( NOX),

volatile organic carbon (VOC),

particulate matter (PM), sulfur dioxide

(SO2), and carbon monoxide (CO). Of

these pollutants, EPA monetized the

human health benefits or impacts

associated with VOC, PM, and SO2

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. SO2 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 SO2. 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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6888 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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 WBFcuttings 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

Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations 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., C7 –C18 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.

6890 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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.,

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

6892 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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 SBFcuttings 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 sciencebased 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 guidelinelisted 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 reestablished 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

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

6894 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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

LC50 (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 SyntheticBased Drilling Fluids and other NonAqueous 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)

Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations 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, Nonaqueous drilling fluids, Oil and gas

extraction, Pollution prevention,

Synthetic based drilling fluids, Waste

treatment and disposal, Water nondispersible 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 § 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:

§ 9.1 OMB approvals under the Paperwork

Reduction Act.

* * * * *

40 CFR citation OMB control

No.

*****

Oil and Gas Extraction Point

Source Category:

435.13 ................................ 2040–0230

435.15 ................................ 2040–0230

435.43 ................................ 2040–0230

40 CFR citation OMB control

No.

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:

§ 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

6896 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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, C16–C18 internal olefins,

and C8–C16 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 LC50 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

Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations 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 C16–C18

linear alpha olefins. C16–C18 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 LC50 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 LC50 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 LC50 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) C16–C18 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) C16–C18 internal olefin drilling

fluid means a C16–C18 internal olefin

drilling fluid formulated as specified in

Appendix 8 of subpart A of this part.

(tt) C12–C14 ester and C8 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 § 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:

§ 435.12 Effluent limitations guidelines

representing the degree of effluent

reduction attainable by the application of

the best practicable control technology

currently available (BPT).

* * * * *

6898 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

BPT EFFLUENT LIMITATIONS—OIL AND GREASE

[In milligrams per liter]

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

Residual

chlorine

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 § 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:

§ 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

Waste source Pollutant parameter BAT effluent limitation

*******

Drilling fluids and drill cuttings:

*******

(B) For facilities located beyond 3

miles from shore:

Water-based drilling fluids and

associated drill cuttings.

SPP Toxicity .................................. Minimum 96-hour LC50 of the SPP Toxicity Test 2 shall be 3% by 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 fluids

(NAFs).

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

Drill cuttings associated with nonaqueous drilling fluids:

Stock Limitations (C16–C18 internal olefin).Mercury .......................................... 1 mg/kg dry weight maximum in the stock barite.

Cadmium ........................................ 3 mg/kg dry weight maximum in the stock barite.

Polynuclear Aromatic Hydrocarbons (PAH).PAH mass ratio 5 shall not exceed 1x10¥5.

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

Biodegradation rate ....................... Biodegradation rate ratio 7 shall not exceed 1.0.

Discharge Limitations ............. Diesel oil ........................................ No discharge.

SPP Toxicity .................................. Minimum 96-hour LC50 of the SPP Toxicity Test 2 shall be 3% by volume.

Sediment toxicity ............................ Drilling fluid sediment toxicity ratio 8 shall not exceed 1.0.

Formation Oil ................................. No discharge.9

Base fluid retained on cuttings ...... For NAFs that meet the stock limitations (C16–C18 internal olefin) in

this table, the maximum weighted mass ratio averaged over all NAF

well sections shall be 6.9 g-NAF base fluid/100 g-wet drill

cuttings.10

For NAFs that meet the C12–C14 ester or C8 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.

Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations 6899

BAT EFFLUENT LIMITATIONS—Continued

Waste source Pollutant parameter BAT effluent limitation

* * * * * **

* * * * * **

2As determined by the suspended particulate phase (SPP) toxicity test (Appendix 2 of subpart A of this part).

3As determined by the static sheen test (Appendix 1 of subpart A of this part).

* * * * * **

5PAH mass ratio = Mass (g) of PAH (as phenanthrene)/Mass (g) of stock base fluid as determined by EPA Method 1654, Revision A, (specified at § 435.11(u)) entitled ‘‘PAH Content of Oil by HPLC/UV,’’ December 1992, which is published in Methods for the Determination of Diesel,

Mineral, and Crude Oils in Offshore Oil and Gas Industry Discharges, EPA–821–R–92–008. This incorporation by reference was approved by 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. 6Base fluid sediment toxicity ratio = 10-day LC50 of C16–C18 internal olefin/10-day LC50 of stock base fluid as determined by ASTM E 1367–92

[specified at § 435.11(ee)] method: ‘‘Standard Guide for Conducting 10-day Static Sediment Toxicity Tests with Marine and 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. 7Biodegradation rate ratio = Cumulative gas production (ml) of C16–C18 internal olefin/Cumulative gas production (ml) of stock base fluid, both

at 275 days as determined by ISO 11734:1995 [specified at § 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 LC50 of C16–C18 internal olefin drilling fluid/4-day LC50 of drilling fluid removed from drill cuttings at

the solids control equipment as determined by ASTM E 1367–92 (specified at § 435.11(ee)) method: ‘‘Standard Guide for Conducting 10-day

Static Sediment Toxicity Tests with Marine and Estuarine Amphipods,’’ 1992, after preparing the 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. 9As 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 (C16–C18 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 LC50 of C12–C14 ester or C8 ester /10-day LC50 of stock base fluid as determined by ASTM E 1367–92 (specified at § 435.11(ee)) method:

‘‘Standard Guide for Conducting 10-day Static Sediment Toxicity Tests with Marine and Estuarine Amphipods,’’ 1992, after preparing the 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 C12–C14 ester or C8 ester/Cumulative gas production (ml) of stock

base fluid, both at 275 days as determined by ISO 11734:1995 (specified at § 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 (C16–C18 internal olefin) defined above in this table.

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

follows:

§ 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

Waste source Pollutant parameter BCT effluent limitation

*******

Drilling fluids and drill cuttings:

6900 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

BCT EFFLUENT LIMITATIONS—Continued

Waste source Pollutant parameter BCT effluent limitation

*******

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

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

Non-aqueous drilling fluids .............................................. ................................................................................................. No discharge.

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

* * * * * **

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

*******

6. In § 435.15 the table is amended by revising entry (B) under ‘‘Drilling fluids and drill cuttings’’ and by revising

footnote 2 and adding footnotes 5–11 to read as follows:

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

* * * * *

NEW SOURCE PERFORMANCE STANDARDS (NSPS)

Waste source Pollutant parameter NSPS

*******

Drilling fluids and drill cuttings:

*******

(B) For facilities located beyond 3

miles from shore:

Water-based drilling fluids and

associated drill cuttings.

SPP Toxicity .................................. Minimum 96-hour LC50 of the SPP Toxicity Test 2 shall be 3% by volume.

Free oil ........................................... No discharge.3

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 fluids ..... ........................................................ No charge.

Drill cuttings associated with nonaqueous drilling fluids:

Stock Limitations (C16–C18 internal olefin.Mercury .......................................... 1mg/kg dry weight maximum in the stock barite.

Cadmium ........................................ 3 mg/kg dry weight maximum in the stock barite.

Polynuclear Aromatic Hydrocarbons (PAH).PAH mass ratio5 shall not exceed 1×10¥5

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

Biodegradation rate ....................... Biodegradation rate ratio7 shall not exceed 1.0.

Discharge Limitations ............. Diesel oil ........................................ No discharge.

SPP Toxicity .................................. Minimum 96-hour LC50 of the SPP Toxicity Test 2 shall be 3% by volume.

Sediment toxicity ............................ Drilling fluid sediment toxicity ratio 8 shall not exceed 1.0.

Formation Oil ................................. No discharge.9

Base fluid retained on cuttings ...... For NAFs that meet the stock limitations (C16–C18 internal olefin) in

this table, the maximum weighted mass ratio averaged over all NAF

well sections shall be 6.9 g–NAF base fluid/100 g-wet drill

cuttings.10

For NAFs that meet the C12–C14 ester or C8 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.

* * ** * * *

* * * * * **

2As determined by the suspended particulate phase (SPP) toxicity test (Appendix 2 of subpart A of this part).

3As determined by the static sheen test (appendix 1 of subpart A of this part).

* * ** * **

5PAH mass ratio = Mass (g) of PAH (as phenanthrene)/Mass (g) of stock base fluid as determined by EPA Method 1654, Revision A, (specified at § 435.11(u)) entitled ‘‘PAH Content of Oil by HPLC/UV,’’ December 1992, which is published in Methods for the Determination of Diesel,

Mineral, and Crude Oils in Offshore Oil and Gas Industry Discharges, EPA–821–R–92–008. This incorporation by reference was approved by 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.

Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations 6901

6Base fluid sediment toxicity ratio = 10-day LC50 of C16–C18 internal olefin/10-day LC50 of stock base fluid as determined by ASTM E 1367–92

(specified at § 435.11(ee)) method: ‘‘Standard Guide for Conducting 10-day Static Sediment Toxicity Tests with Marine and 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. 7Biodegradation rate ratio = Cumulative gas production (ml) of C16–C18 internal olefin/Cumulative gas production (ml) of stock base fluid, both

at 275 days as determined by ISO 11734:1995 (specified at § 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 LC50 of C16–C18 internal olefin drilling fluid/4-day LC50 of drilling fluid removed from drill cuttings at

the solids control equipment as determined by ASTM E 1367–92 (specified at § 435.11(ee)) method: ‘‘Standard Guide for Conducting 10-day

Static Sediment Toxicity Tests with Marine and Estuarine Amphipods,’’ 1992, after preparing the 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. 9As 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 (C16–C18 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 LC50 of C12–C14 ester or C8 ester /10-day LC50 of stock base fluid as determined by ASTM E 1367–92 [specified at § 435.11(ee)] method:

‘‘Standard Guide for Conducting 10-day Static Sediment Toxicity Tests with Marine and Estuarine Amphipods,’’ 1992, after preparing the 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 C12–C14 ester or C8 ester/Cumulative gas production (ml) of stock

base fluid, both at 275 days as determined by ISO 11734:1995 (specified at § 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 (C16–C18 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 presssieved 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

°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)] × [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]} × (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)] × [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)] × [Dry Weight

Sediment (kg)] × [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

LC50 values.

5. Tests for homogeneity of base fluid in

sediment are to be performed during the

procedure development phase. Because of

6902 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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 LC50, 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°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±1°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 allglass systems may be required.

4.3 Glassware shall be cleaned by rinsing

with solvent and baking at 400 °C for a

minimum of 1 hour.

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

within 2 hours and holding 450 °C within

±10 °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 °C for a

minimum of 1 hour.

6.2.3.2 Glass volumetric pipettes or gas

tight syringes—1.0-mL ± 1% and 0.5-mL ±

1%.

6.2.3.3 Volumetric flasks—Glass, class A,

10-mL, 50-mL and 100-mL.

6.2.3.4—Sample vials—Glass, 1- to 3-mL

(baked at 400 °C for a minimum of 1 hour)

with PTFE-lined screw or crimp cap.

6.2.3.5 Centrifuge and centrifuge tubes—

Centrifuge capable of 10,000 rpm, or better,

(International Equipment Co., IEC Centra

MP4 or equivalent) and 50-mL centrifuge

tubes (Nalgene, Ultratube, Thin Wall 25×89

mm, #3410–2539).

6.3 Gas Chromatograph/Mass

Spectrometer (GC/MS):

6.3.1 Gas Chromatograph—An analytical

system complete with a temperatureprogrammable 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) × 0.32

mm ID (or 0.25 mm ID) 1μm film thickness

(or 0.25μm 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 °C

to 20 °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 μL 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

6904 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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 °C in screwcapped 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 ±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 PTFEor 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 °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–2Sp to P+2Sp. For

example, if P=90% and Sp=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

μL of the internal standard solution (Section

7.2.3 of this appendix) and analyze a 1-μL

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 = [D1 ¥ D2]/[(D1 + D2)/2] × 100 [1]

where:

D1 = Concentration of crude oil in the

sample; and

D2 = 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 oilequivalent 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 °C

Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations 6905

TABLE 1.—GAS CHROMATOGRAPH/

MASS SPECTROMETER (GC/MS)

OPERATION CONDITIONS—Continued

Parameter Setting

Transfer line .............. 280 °C

Detector ..................... 280 °C

Initial Temperature .... 50 °C

Initial Time ................. 5 minutes

Ramp ......................... 50 to 300 °C @ 5 °C

per minute

Final Temperature ..... 300 °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

Compound

Approximate

retention

time (minutes)

Toluene ..................................... 5.6

Octane, n¥C8 .......................... 7.2

Ethylbenzene ............................ 10.3

1,2,4-Trimethylbenzene ............ 16.0

Decane, ¥C10 .......................... 16.1

TCB (Internal Standard) ........... 21.3

Dodecane, ¥C12 ...................... 22.9

1-Methylnaphthalene ................ 26.7

1-Tetradecene .......................... 28.4

Tetradecane, ¥C14 .................. 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 μL of the

TCB internal standard solution.

10.3.2 Inject 1.0 μL 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 μL of

the TCB internal standard solution.

10.3.4 Inject 1.0 μL 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 (C8–

C13) 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 μL 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 C8 to

C13. Obtain the TIC area of the internal

standard (TCB). Subtract the TCB area from

the C8–C13 area to obtain the true C8–C13 area.

Using the C8–C13 and TCB areas, and known

internal standard concentration, generate a

linear regression calibration using the

internal standard method. The r2 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 r2 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

μL 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 μL 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 C8 to C13 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 C8 to C13 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).

6906 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

TABLE 3.—RECOMMENDED ION MASS NUMBERS

Selected ion mass numbers Corresponding aromatic compounds Typical rentention

time (minutes)

91 ............................................................................................. Methylbenzene ........................................................................ 6.0

Ethylbenzene ........................................................................... 10.3

1,4-Dimethylbenzene ............................................................... 10.9

1,3-Dimethylbenzene ............................................................... 10.9

1,2-Dimethylbenzene ............................................................... 11.9

105 ........................................................................................... 1,3,5-Trimethylbenzene ........................................................... 15.1

1,2,4-Trimethylbenzene ........................................................... 16.0

1,2,3-Trimethylbenzene ........................................................... 17.4

156 ........................................................................................... 2,6-Dimethylnaphthalene ......................................................... 28.9

1,2-Dimethylnaphthalene ......................................................... 29.4

1,3-Dimethylnaphthalene ......................................................... 29.7

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 C10 to C13 n-alkanes and corresponding

target aromatics.

11.3.2 Using the calibration data,

establish the identity of the C8 to C13 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 nalkanes from C8 to C13 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 C8 to C13 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

C7 to C9, and the absence of n-alkanes greater

than C25.

11.5.4 Crude oils can usually be

distinguished by the presence of high

aromatics, increased intensities of C8 to C13

peaks, and/ or the presence of higher

hydrocarbons of C25 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 C8–C13 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 C8 to C13 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 μL 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 μL 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 ± 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 C8 and C13 (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 C8 to C13 TIC area, the TCB

area in the clean NAF sample and the TIC

linear regression curve, compute the oil

equivalent concentration of the C8 to C13

retention time range in the clean NAF.

Note: The actual TIC area of the C8 to C13

is equal to the C8 to C13 area minus the area

of the TCB.

12.1.2 Using the corresponding

information for the authentic sample,

compute the oil equivalent concentration of

the C8 to C13 retention time range in the

authentic sample.

12.1.3 Calculate the concentration (% oil)

of oil in the sample by subtracting the oil

Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations 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±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 NonAqueous 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 nonaqueous 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 ±5°C in the range of 100–

250 °C.

6.3 Equipment for sample extraction.

6.3.1 Vials—Glass, 25 mL and 4 mL, with

Teflon-lined screw caps, baked at 200–250 °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

6908 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

delivery, with appropriate size disposable

pipette tips, calibrated to within ±0.5%.

6.3.4 Glass stirring rod.

6.3.5 Vortex mixer.

6.3.6 Disposable syringes—Plastic, 5 mL.

6.3.7 Teflon syringe filter, 25-mm,

0.45μm pore size—Acrodisc CR Teflon (or

equivalent).

6.3.8 Reverse Phase Extraction C18

Cartridge—Waters Sep-PakPlus, C18

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′′×7.5′′×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 reprocess 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 °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

C18 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 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 C18 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 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

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

μm 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 C18 cartridge with the

sample identification.

11.2.9 Place the labeled Sep Pak C18

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 C18 cartridge.

11.2.12 Condition the C18 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 C18 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 C18 cartridge.

Note: Depress the plunger just to the point

when no liquid remains in the syringe barrel.

Do not force air through the cartridge. 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 C18 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 C18

cartridge.

Note: Depress the plunger just to the point

when no liquid remains in the syringe barrel.

Do not force air through the cartridge. Collect

the eluate in a waste vial.

11.2.19 Remove the syringe and labeled

C18 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

6910 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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-cm3 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-cm3.

Precision: ±0.25-cm3.

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

°F (500 °C) and enough to boil off all NAFs.

b. Liquid receiver (10-cm3, 20-cm3)—the

10-cm3 and 20-cm3 receivers are specially

designed cylindrical glassware with rounded

bottom to facilitate cleaning and funnelshaped top to catch falling drops. For

compliance monitoring under the NPDES

program, the analyst shall use the 10-cm3

liquid receiver with 0.1 ml graduations to

achieve greater accuracy.

1. Receiver specifications:

Total volume: 10-cm3, 20-cm3.

Precision (0 to 100%): ±0.05 cm3, ±0.05

cm3.

Outside diameter: 10-mm, 13-mm.

Wall thickness: 1.5±0.1mm, 1.2±0.1mm.

Frequency of graduation marks (0 to

100%): 0.10-cm3, 0.10-cm3.

Calibration: To contain ‘‘TC’’ @ 20°C.

Scale: cm3, cm3

2. Material—Pyrex or equivalent glass.

c. Toploading balance—capable of

weighing 2000 g and precision of at least 0.1

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 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), cm3.

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 (Mw)

equals the mass of the retort assembly with

the wet cuttings sample (B) minus the mass

of the empty retort assembly (A).

Mw = B¥A [1]

2. Mass of the dry retorted cuttings (MD)

equals the mass of the cooled retort assembly

(E) minus the mass of the empty retort

assembly (A).

MD = E¥A [2]

3. Mass of the NAF base fluid (MBF) 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).

MBF = D¥(C + V) [3]

Note: Assuming the density of water is 1

g/cm3, the volume of water is equivalent to

the mass of the water.

b. Mass balance requirement:

The sum of MD, MBF, and V shall be within

5% of the mass of the wet sample.

(MD + MBF + V)/Mw = 0.95 to 1.05 [4]

The procedure shall be repeated if 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 (%BFi) for the

sampled discharge ‘‘i’’ is equal to 100 times

the mass of the NAF base fluid (MBF) divided

by the mass of the wet cuttings sample (Mw).

%BFi = (MBF/Mw) × 100 [5]

Operators discharging small volume NAFcuttings discharges which do not occur

during a NAF-cuttings discharge sampling

interval (i.e., displaced interfaces,

accumulated solids in sand traps, pit cleanout solids, or centrifuge discharges while

cutting mud weight) shall either: (a) Measure

the mass percent NAF base fluid retained on

the cuttings (%BFSVD) 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 NAFcuttings, 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:

Xi = (Fi)/(G) [6]

where:

Xi = Mass NAF-cuttings discharge fraction for

NAF-cuttings, fines, or accumulated

solids discharge ‘‘i’’, (unitless)

Fi = 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 Fi, (kg)

If an operator has more than one point of

NAF-cuttings discharge, the mass faction (Xi)

must be determined by: (a) Direct

measurement (see Equation 6 of this

Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations 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 ‘‘Fi’’ (see Equation 6 of this

Appendix) for fines and accumulated solids,

using Equation 6A of this Appendix to

calculate ‘‘GEST’’ for use as ‘‘G’’ in Equation

6 of this Appendix, and calculating the mass

(kg) of NAF-cuttings discharged from the

cuttings dryer (Fi) as the difference between

the mass of ‘‘GEST’’ 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).

GEST = Estimated mass of all NAF-cuttings

discharges into the ocean during the

same period of time as used to calculate

Fi (see Equation 6 of this Appendix), (kg)

[6A]

where:

GEST = Hole Volume (bbl) × (396.9 kg/bbl) ×

(1 + Z/100)

Z = The base fluid retained on cuttings

limitation or standard (%) which apply

to the NAF being discharge (see

§§ 435.13. and 435.15).

Hole Volume (bbl) = [Cross-Section Area of

NAF interval (in2)] × Average Rate of

Penetration (feet/hr) × period of time

(min) used to calculate Fi (see Equation

6 of this Appendix) × (1 hr/60 min) × (1

bbl/5.61 ft3) × (1 ft/12 in)2

Cross-Section Area of NAF interval (in2) =

(3.14 × [Bit Diameter (in)]2)/4

Bit Diameter (in) = Diameter of drilling bit for

the NAF interval producing drilling

cuttings during the same period of time

as used to calculate Fi (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 Fi (see

Equation 6 of this Appendix)

Note: Operators with one NAF-cuttings

discharge may set the mass NAF-cuttings

discharge fraction (Xi) 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 (%BFT) is calculated every

time a set of retorts is performed. The single

total mass percent NAF base fluid retained

on cuttings value (%BFT) is calculated as:

%BFT,j = Σ(Xi)×(%BFi) [7]

where:

%BFT,j = Total mass percent NAF base fluid

retained on cuttings value for retort set

‘‘j’’ (unitless as percentage, %)

Xi = Mass NAF-cuttings discharge fraction for

NAF-cuttings, fines, or accumulated

solids discharge ‘‘i’’, (unitless)

%BFi = Mass percent NAF base fluid retained

on the cuttings for NAF-cuttings, fines,

or accumulated solids discharge ‘‘i’’ ,

(unitless as percentage, %)

Note: ΣXi = 1.

Operators with one NAF-cuttings discharge

may set %BFT,j equal to %BFi.

6. Operators performing dual gradient

drilling operations may require 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 (%BFwell) 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 § 435.13 and

footnote 5 of the table in § 435.43) or the

‘‘maximum weighted mass ratio averaged

over all NAF well sections’’ NSPS discharge

limitations (see the table in § 435.15 and

footnote 5 of the table in § 435.45). The

weighted mass ratio averaged over all NAF

well sections (%BFwell) is calculated as the

arithmetic average of all total mass percent

NAF base fluid retained on cuttings values

(%BFT) and is given by the following

expression:

%BFwell = [j=1 to j=n Σ (%BFT,j)]/n [8]

where:

%BFwell = Weighted mass ratio averaged over

all NAF well sections (unitless as

percentage, %)

%BFT,j = 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 (%BFwell). The mass fraction of

the small volume NAF-cuttings discharges

(XSVD) will be determined by dividing the

mass of the small volume NAF-cuttings

discharges (FSVD) by the total mass of NAFcuttings discharges for the well drilling

operation (GWELL + FSVD).

XSVD = FSVD / (GWELL + FSVD) [9]

where:

XSVD = mass fraction of the small volume

NAF-cuttings discharges (unitless)

FSVD = mass of the small volume NAFcuttings discharges (kg)

GWELL = mass of total NAF-cuttings from the

well (kg)

The mass of small volume NAF-cuttings

discharges (FSVD) shall be determined by

multiplying the density of the small volume

NAF-cuttings discharges (ρsvd) times the

volume of the small volume NAF-cuttings

discharges (VSVD).

FSVD = ρsvd × VSVD [10]

where:

FSVD = mass of small volume NAF-cuttings

discharges (kg)

ρsvd = density of the small volume NAFcuttings discharges (kg/bbl)

VSVD = volume of the small volume NAFcuttings discharges (bbl)

The density of the small volume NAFcuttings discharges shall be measured. The

volume of small volume discharges (VSVD)

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 (GWELL) 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

(VWELL) for all NAF well sections times a

default value for the density the formation of

2.5 g/cm3 (396.9 kg/bbl).

6912 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

G i n V bbl WELL WELL =+ = ( ) [ ] ( ) 

  1 1 396 9 to j = n %BF (kg/bbl) [11] ∑ Tj / . × ( ) ×

where:

GWELL = total mass of NAF-cuttings discharges for the well (kg)

[j = 1 to j = n Σ2(%BFTj)]/n = see Equation 8 of this Appendix (unitless as a percentage)

VWELL = total hole volume (VWELL) for all NAF well sections (bbl)

The total hole volume of NAF well sections (VWELL) will be calculated as:

V barrels WELL ( ) = × ∑ Bit diameter (in) change in measured depth (ft) [12]

2

1029

For wells where small volume discharges associated with cuttings are made, %BFWELL becomes:

% /% BF X i n X BF WELL SVD SVD SVD = − ( ) ( ) 1 1 to j = n %BF [13] × = [ ] ∑( ) Tj + ×

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 (%BFT) 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 NAFcuttings 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 NAFcuttings 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 NAFcuttings samples at the point where NAFcuttings 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 NAFcuttings 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 (Fi, 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 NAFcuttings 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 (cm3/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 NAFcuttings 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

Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations 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 NAFcuttings 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 (%BFT) 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 (%BFT) for

each NAF-cuttings sampling interval: (1) Date

and starting and stopping times of NAFcuttings 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 NAFcuttings 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 (%BFwell) 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 (%BFwell) 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 NAFequipment 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.

6914 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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 waterbased 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 (%BFwell) of

the retort analyses taken during the first 0.33

X feet drilled with NAF.

6.5.1 When the arithmetic average

(%BFwell) 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 §§ 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

(%BFwell) 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 §§ 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

(%BFwell) 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 §§ 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

(%BFwell) 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 §§ 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

(%BFwell) 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 §§ 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 retortmonitored and non-retort-monitored NAFcuttings 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 C16–C18 Internal Olefin Drilling

Fluid Formulation

The reference C16–C18 internal olefin

drilling fluid used to determine the drilling

fluid sediment toxicity ratio and compliance

with the BAT sediment toxicity discharge

limitation (see § 435.13) and NSPS (see

§ 435.15) shall be formulated to meet the

specifications in Table 1 of this appendix.

Drilling fluid sediment toxicity ratio = 4-

day LC50 of C16–C18 internal olefin drilling

fluid/4-day LC50 of drilling fluid removed

from cuttings at the solids control equipment

as determined by ASTM E1367–92

[incorporated by reference and specified at

§ 435.11(ee)] and supplemented with the

sediment preparation procedure (Appendix 3

of subpart A of this part).

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

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

SBF (pounds per gallon)

Reference C16–C18 IOs

SBF synthetic to water

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:

§ 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

Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations 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, eyewash 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, C16–C18 internal olefins,

and C8–C16 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 LC50 value

allowed as measured in any single

sample of the discharged waste stream.

6916 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

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 C16–C18

linear alpha olefins. C16–C18 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 LC50 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 § 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:

§ 435.42 Effluent limitations guidelines

representing the degree of effluent

reduction attainable by the application of

the best practicable control technology

currently available (BPT).

* * * * *

Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations 6917

BPT EFFLUENT LIMITATIONS—OIL AND GREASE

[In milligrams per liter]

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

Residual

chlorine

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 § 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:

§ 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

Waste source Pollutant parameter BAT effluent limitation

*******

Drilling fluids, Drill cuttings, and

Dewatering effluent: 1

*******

(B) Cook Inlet:

Water-based drilling fluids, drill

cuttings, and dewatering effluent.

SPP Toxicity .................................. Minimum 96-hour LC50 of the SPP Toxicity 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 fluids

and dewatering effluent.

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

Drill cuttings associated with

non-aqueous drilling fluids.

................................................... No discharge.5

*******

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

*******

4As determined by the suspended particulate phase (SPP) toxicity test (see Appendix 2 of Subpart A of this part). 5When Cook Inlet operators cannot comply with this no discharge requirement due to technical limitations (see Appendix 1 of Subpart D of this

part), Cook Inlet operators shall meet the same stock limitations (C16-C18 internal olefin) and discharge limitations for drill cuttings associated with

non-aqueous drilling fluids for operators in Offshore waters (see § 435.13) in order to discharge drill cuttings associated with non-aqueous drilling

fluids.

11. In § 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:

§ 435.44 Effluent limitations guidelines

representing the degree of effluent

reduction attainable by the application of

the best conventional pollutant control

technology (BCT).

* * * * *

6918 Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations

BCT EFFLUENT LIMITATIONS

Waste source Pollutant parameter BCT effluent limitation

*******

Drilling fluids, Drill cuttings, and Dewatering effluent: 1

*******

Cook Inlet:

Water-based drilling fluids, drill cuttings, and dewatering

effluent.

Free Oil ................................................................................... No discharge.2

Non-aqueous drilling fluids and dewatering effluent ....... ............................................................................................ No discharge.

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

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

* * * * *

12. In § 435.45 the table is amended

by revising entry (B) under ‘‘Drilling

fluids, drill cuttings, and dewatering

effluent’’ and by revising footnote 4 and

adding footnote 5 to read as follows:

§ 435.45 Standards of performance for

new sources (NSPS).

* * * * *

NEW SOURCE PERFORMANCE STANDARDS (NSPS)

Waste Source Pollutant parameter NSPS

*******

Drilling fluids, Drill cuttings, and

Dewatering effluent: 1

*******

(B) Cook Inlet:

Water-based drilling fluids, drill

cuttings, and dewatering effluent.

SPP Toxicity .................................. Minimum 96-hour LC50 of the SPP Toxicity 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 fluids

and dewatering effluent.

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

Drill cuttings associated with

non-aqueous drilling fluids.

................................................... No discharge.5

*******

1 NSPS for dewatering effluent are applicable prospectively. NSPS in this rule are not applicable to discharges of dewatering effluent from 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. 2As determined by the static sheen test (see Appendix 1 of subpart A of this part).

* * * * * **

4As determined by the suspended particulate phase (SPP) toxicity test (see Appendix 2 of subpart A of this part). 5When Cook Inlet operators cannot comply with this no discharge requirement due to technical limitations (see Appendix 1 of subpart D of this

part), Cook Inlet operators shall meet the same stock limitations (C16–C18 internal olefin) and discharge limitations for drill cuttings associated

with non-aqueous drilling fluids for operators in Offshore waters (see § 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 EMOCuttings 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 syntheticbased 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

Federal Register / Vol. 66, No. 14 / Monday, January 22, 2001 / Rules and Regulations 6919

preclude Coastal Cook Inlet operators from

complying with the zero discharge

requirement for EMO-cuttings and SBFcuttings. 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 EMOcuttings 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 SBFcuttings 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 EMOcuttings 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 SBFcuttings 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 SBFcuttings 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 EMOcuttings 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 EMOcuttings 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