9428 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

ENVIRONMENTAL PROTECTION

AGENCY

40 CFR Part 435

[FRL–5149–7]

RIN 2040–AB72

Effluent Limitations Guidelines,

Pretreatment Standards, and New

Source Performance Standards: Oil

and Gas Extraction Point Source

Category, Coastal Subcategory

AGENCY: Environmental Protection

Agency (EPA).

ACTION: Proposed rule.

SUMMARY: This proposed regulation

would limit the discharge of pollutants

into waters of the United States and the

introduction of pollutants into publiclyowned treatment works by existing and

new facilities in the coastal subcategory

of the oil and gas extraction point

source category.

This proposed regulation would

establish effluent limitations guidelines

and new source performance standards

(NSPS) for direct dischargers based on

‘‘best practicable control technology

currently available’’ (BPT), ‘‘best

conventional pollutant control

technology’’ (BCT), ‘‘best available

technology economically achievable’’

(BAT), and ‘‘best available demonstrated

control technology’’ (BADCT) for new

sources. The proposal also would

establish ‘‘pretreatment standards for

new sources’’ (PSNS) and ‘‘pretreatment

standards for existing sources’’ (PSES)

for facilities discharging their

wastewaters to publicly-owned

treatment works (POTWs).

This regulation will reduce the

discharge of pollutants into U.S. coastal

water bodies by 4.3 billion pounds,

thereby also reducing the impacts these

discharges would otherwise incur to

aquatic life and/or human health. As a

result of consultation with stakeholders,

the preamble solicits comments and

data not only on issues raised by EPA,

but also on those raised by State and

local governments who will be

implementing these regulations and by

industry representatives who will be

affected by them.

This proposal does not take into

account the regulatory effects of the

recently published final EPA Region VI

NPDES General Permits for production

facilities (January 9, 1995). With these

permits in effect, the costs of this

proposal will be reduced and the actual

reduction of pollutant loadings to

coastal waters would be approximately

71 percent less, or 1.25 billion pounds

per year, due to today’s proposal. EPA

will more fully incorporate the

regulatory effects of the Region VI

General Permits upon promulgation of

the final rule.

DATES: Comments on the proposal must

be received by May 18, 1995. Two

public meetings will be held during the

comment period: on March 7, 1995, in

New Orleans, Louisiana and on March

21, 1995, in Seattle, Washington. Both

meetings will be held from 9:00 am to

12:00 pm.

ADDRESSES: Submit comments in

writing to: Ms. Allison Wiedeman,

Engineering and Analysis Division

(4303), U.S. EPA, 401 M Street, S.W.,

Washington, DC 20460. Please submit

any references cited in your comments.

EPA would appreciate an original and

two copies of your comments and

enclosures (including references).

The public record supporting the

proposed effluent limitations guidelines

and standards is in the Water Docket

located in the basement of the EPA

Headquarters building, Room L102, 401

M Street S.W., Washington, DC 20460.

For access to Docket materials call (202)

260–3027. The Docket staff requests that

interested parties call, between 9:00 am

and 3:30 pm, for an appointment before

visiting the docket. The EPA regulations

at 40 CFR Part 2 provide that a

reasonable fee may be charged for

copying.

The workshops covering the

rulemaking will be held at the Minerals

Management Service, Gulf of Mexico

OCS Region, Office of the Regional

Director, 1201 Elmwood Park Boulevard

in New Orleans, Louisiana on March 7,

1995, and at the Federal Building, 915

2nd Avenue, North Auditorium in

Seattle, Washington on March 21, 1995.

The background documents are

available from the Office of Water

Resource Center, RC–4100, at the U.S.

EPA, Washington, DC address shown

above; telephone (202) 260–7786 for the

voice mail publication request line.

FOR FURTHER INFORMATION CONTACT: For

technical information contact Ms.

Allison Wiedeman at (202) 260–7179.

For economic information contact Dr.

Matthew Clark at (202) 260–7192.

SUPPLEMENTARY INFORMATION:

Public Meeting

No meeting materials will be

distributed in advance of these

meetings: all material will be distributed

at the meetings. See ADDRESSES for

information on location of the public

meetings.

Docket

EPA notes that many documents in

the record supporting these proposed

rules have been claimed as confidential

business information (CBI) and,

therefore, are not included in the record

that is available to the public in the

Water Docket. To support the

rulemaking, EPA is presenting certain

information in aggregated form or is

masking facility identities to preserve

confidentiality claims. Further, the

Agency has withheld from disclosure

some data not claimed as confidential

business information because release of

this information could indirectly reveal

information claimed to be confidential.

Some facility-specific data, which

have been claimed as confidential

business information, are available to

the company that submitted the

information. To ensure that all CBI is

protected in accordance with EPA

regulations, any requests for companyspecific data should be submitted to

EPA on company letterhead and signed

by a responsible official authorized to

receive such data. The request must list

the specific data requested and include

the following statement, ‘‘I certify that

EPA is authorized to transfer

confidential business information

submitted by my company, and that I

am authorized to receive it.’’

Overview

This preamble includes a description

of the legal authority for these rules; a

summary of the proposal; a description

of the background documents that

support these proposed regulations and

other background information; and a

description of the technical and

economic methodologies used by EPA

to develop these regulations. This

preamble also solicits comment and

data on specific areas of interest. The

definitions, acronyms, and

abbreviations used in this notice are

defined in Appendix A to the preamble.

Organization of This Document

I. Legal Authority

II. Summary and Scope of the Proposed

Regulations

A. Purpose of this Rulemaking

B. Summary of Proposed Coastal

Guidelines

C. The EPA Region VI Coastal Oil and Gas

Production NPDES General Permit

D. Preventing the Circumvention of

Effluent Limitations Guidelines and New

Source Performance Standards

E. Common Sense Initiative

III. Background

A. Clean Water Act

B. Pollution Prevention Act

C. Coastal Subcategory Definition

D. New Source Definition

E. Summary of Public Participation

IV. Description of the Industry

A. Industry Description

B. Location

C. Activity
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9429

D. Waste Streams

E. Current NPDES Permits

V. Summary of Data Gathering Efforts

A. Information Used From the Offshore

Guidelines

B. 1993 Coastal Oil and Gas Questionnaire

C. Investigation of Solids Control

Technologies for Drilling Fluids

D. Sampling Visits to 10 Gulf of Mexico

Coastal Production Facilities

E. State Discharge Monitoring Reports

F. Commercial Disposal Operations

G. Evaluation of NORM in Produced

Waters

H. Alaska Operations

I. Region X Drilling Fluid Toxicity Data

Study

J. California Operations

K. OSW Sampling Program

L. Estimation of the Inner Boundary of the

Territorial Seas

. VI. Development of Effluent Limitations

Guidelines and Standards

A. Drilling Fluids and Drill Cuttings

(Drilling Wastes)

B. Produced Water

C. Produced Sand

D. Deck Drainage

E. Treatment, Workover, and Completion

Fluids

F. Domestic Wastes

G. Sanitary Wastes

VII. Economic Analysis

A. Introduction

B. Economic Methodology

C. Summary of Costs and Economic

Impacts

D. Produced Water

E. Drilling Fluids and Drill Cuttings

F. Treatment, Workover, and Completion

Fluids

G. Cost-Effectiveness Analysis

H. Regulatory Flexibility

VIII. Non Water Quality Environmental

Impacts

A. Drilling Fluids and Cuttings

B. Produced Water

C. Treatment, Workover and Completion

Fluids

IX. Executive Order 12866

X. Executive Order 12875

XI. Paperwork Reduction Act

XII. Environmental Benefits Analysis

A. Introduction

B. Quantitative Estimate of Benefits

C. Description of Non-Quantified Benefits

D. EPA Region VI Production Permit

XIII. Regulatory Implementation

A. Toxicity Limitation for Drilling Fluids

and Drill Cuttings

B. Diesel Prohibition for Drilling Fluids

and Drill Cuttings

C. Upset and Bypass Provisions

D. Variances and Modifications

E. Synthetic Drilling Fluids

XIV. Related Rulemakings

XV. Solicitation of Data and Comments

XVI. Background Documents

Appendix A—Abbreviations, Acronyms, and

Other Terms Used in This Notice

I. Legal Authority

These regulations are being proposed

under the authority of sections 301, 304,

306, 307, 308, and 501 of the Clean

Water Act (CWA), 33 U.S.C. sections

1311, 1314, 1316, 1317, 1318, and 1361.

II. Summary and Scope of the Proposed

Regulations

A. Purpose of This Rulemaking

The purpose of this rulemaking is to

propose effluent limitations guidelines

and standards for the control of the

discharge of pollutants for the Coastal

Subcategory of the Oil and Gas

Extraction Point Source Category. The

discharge limitations proposed today

apply to discharges from coastal oil and

gas extraction facilities, including

exploration, development and

production operations. The processes

and operations which comprise the

coastal oil and gas subcategory

(Standard Industrial Classification (SIC)

Major Group 13) are currently regulated

under 40 CFR Part 435, Subpart D.

These regulations are being proposed

under the authority of the CWA, as

discussed in Section I of this notice. The

regulations are also being proposed

pursuant to a Consent Decree entered in

NRDC et al. v. Reilly, (D D.C. No. 89–

2980, January 31, 1992) and are

consistent with EPA’s latest Effluent

Guidelines Plan under section 304(m) of

the CWA. (See 59 FR 44234, August 26,

1994). The existing effluent limitations

guidelines, which were issued on April

13, 1979 (44 FR 22069), are based on the

achievement of best practicable control

technology currently available (BPT).

This proposed rule is referred to as the

Coastal Guidelines throughout this

preamble.

This summary section highlights key

aspects of the proposed rule. The

technology descriptions discussed later

in this notice are presented in

abbreviated form; more detailed

descriptions are included in the

Development Document for Proposed

Effluent Limitations Guidelines and

Standards for the Coastal Subcategory of

the Oil and Gas Extraction Point Source

Category, referred to hereafter as the

‘‘Coastal Technical Development

Document’’. Today’s proposal presents

EPA’s selected technology approach and

several others that were considered in

the regulation development process.

The proposed rule is based on a detailed

evaluation of data acquired during the

development of the proposed

limitations. As indicated below in the

discussion of the specifics of the

proposal, EPA welcomes comment on

all options and issues and encourages

commenters to submit additional data

during the comment period. Also, EPA

is willing to meet with interested parties

during the comment period to ensure

that EPA has the views of all parties and

the best possible data upon which to

base a decision for the final regulation.

EPA emphasizes that it is soliciting

comments on all options suggested in

and raised by this proposal and that it

may adopt any such options or

combination of options in the final rule.

B. Summary of Proposed Coastal

Guidelines

EPA proposes to establish regulations

based on ‘‘best practicable control

technology currently available ’’(BPT)

for one specific wastestream for which

BPT does not currently apply, and ‘‘best

conventional pollutant control

technology’’ (BCT), ‘‘pretreatment

standards for existing sources’’ (PSES),

‘‘best available technology economically

achievable’’ (BAT), best available

demonstrated control technology

(BADCT) for new sources, and

‘‘pretreatment standards for new

sources’’ (PSNS) for the remaining waste

streams.

Under this rule, EPA is co-proposing

three options for the control of drilling

fluids and cuttings (including any

effluent from dewatering pit closures

activities) for BAT effluent limitations

guidelines, and NSPS. The three options

considered contain zero discharge for all

areas, except two of the options contain

allowable discharges for Cook Inlet. One

of these options, which would allow

discharges meeting a more stringent

toxicity limitation if selected for the

final rule, would require an additional

notice for public comment since the

specific toxicity limitation has not been

determined at this time. The three

options are: Option 1—zero discharge of

all areas except Cook Inlet where

discharge limitations require toxicity of

no less than 30,000 ppm (SPP), no

discharge of free oil and diesel oil and

no more than 1 mg/l mercury and 3 mg/

l cadmium in the stock barite, Option

2—zero discharge for all areas except for

Cook Inlet were discharge limitations

would be the same as Option 1, except

toxicity would be set to meet a

limitation between 100,000 ppm (SPP)

and 1 million ppm (SPP), and Option

3—zero discharge for all areas. EPA is

proposing PSES and PSNS prohibiting

all discharges of drilling fluids and drill

cuttings. BCT for drilling fluids and

cuttings is being proposed as zero

discharge for the entire subcategory

except for Cook Inlet, Alaska. BCT

limitations for drilling fluids and

cuttings for Cook Inlet would require no

discharge of free oil (as determined by

the static sheen test).

EPA is proposing to prohibit

discharges of produced water from all

coastal subcategory operations except

those located in Cook Inlet, Alaska,
9430 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

under BAT. Proposed BAT for coastal

facilities in Cook Inlet would limit the

discharge of oil and grease in produced

water to a daily maximum of 42 mg/l

and a thirty day average of 29 mg/l. EPA

is proposing to prohibit discharges of

produced water from all coastal

subcategory operations under NSPA,

PSNS, and PSES. BCT limits for

produced waters in all coastal regions

(including Cook Inlet) would be set

equal to the current BPT limitations,

which limit the discharge of oil and

grease to a daily maximum of 72 mg/l

and a thirty day average of 48 mg/l.

BCT for treatment, workover and

completion fluids is proposed to be set

equal to current BPT limits prohibiting

discharges of free oil, with compliance

to be determined by use of the static

sheen test. EPA is co-proposing two

options for BAT and NSPS limitations

for treatment, workover and completion

finds. Option 1 would require no

discharge of free oil and prohibit

discharges to freshwaters of Texas and

Louisiana. This option reflects current

practice. Option 2 would require the

same limitations as the preferred option

for produced water. This option would

require for BAT that discharges of

treatment, workover and completion

fluids would be prohibited in all coastal

areas except Cook Inlet. In Cook Inlet,

these discharges would be required to

meet a daily maximum oil and grease

limitation of 42 mg/l and a 30 day

average of 29 mg/l. Option 2 would

require zero discharge of these fluids

everywhere for NSPS. EPA proposes

zero discharge as PSES, and PSNS for

treatment, workover and completion

fluids.

BPT, BCT, BAT, NSPS, PSES and

PSNS are being proposed for produced

sand and would prohibit all discharges

of this wastestream. The only BPT

effluent limitations guidelines being

proposed today are for produced sand

which is the only wastestream for which

BPT limits have not been previously

promulgated.

BCT, BAT, and NSPS limits being

proposed for deck drainage would be set

equal to current BPT limits prohibiting

discharges of free oil, with compliance

to be determined by use of the visual

sheen test. EPA is proposing zero

discharge for PSES and PSNS for deck

drainage because collection and capture

of this wastestream is technically

impractical in many situations (as

discussed later in Section VI.D.) such

that its direction to POTW’s would

rarely if ever occur. EPA also believes

that combining this wastestream with

municipal treatment facilities that may

already be at full capacity should not be

encouraged.

BCT is being proposed for domestic

wastes as equal to BPT (which is no

discharge of floating solids) with an

additional requirement prohibiting the

discharge of garbage. BAT is being

proposed for domestic wastes to

prohibit discharge of foam. NSPS is

being proposed for domestic wastes as

equal to BCT and no discharge of foam

and no discharge of garbage. No

pretreatment standards are being

established for domestic wastes.

BCT and NSPS limitations for sanitary

wastes are being proposed as equal to

the current BPT effluent limitations

guidelines. Sanitary waste effluents

from facilities continuously manned by

ten (10) or more persons would contain

a minimum residual chlorine content of

1 mg/1, with the chlorine level

maintained as close to this

concentration as possible. Coastal

facilities continuously manned by nine

or fewer persons or only intermittently

manned by any number of persons must

comply with a prohibition on the

discharge of floating solids. BAT is not

being developed for sanitary wastes

because no toxic or nonconventional

pollutants of concern have been

identified in this waste stream. No

pretreatment standards are being

established for sanitary wastes.

Compliance with these proposed

limitations would result in a yearly

decrease of 4.3 billion pounds of toxic,

nonconventional and conventional

pollutants in produced water, from zero

to 23 million pounds of toxic

nonconventional and conventional

pollutants in drilling fluids and drill

cuttings (depending on the option

considered), and zero to 3.9 million

pounds of toxic, nonconventional, and

conventional pollutants in treatment,

workover, and completion fluids

(depending on the option considered).

EPA expects a variety of human

health, and environmental benefits to

result from these reductions in effluent

loadings. In particular, the benefits

include: Relief to coastal waters which

support spawning grounds, nurseries

and habitats for commercial and

recreational fisheries: Reducing

documented aquatic ‘‘dead zone’’

impacts; reduction of potential cancer

risks to anglers from consuming seafood

contaminated by produced water

radionuclides; and reducing potential

exposure of endangered species to toxic

contaminants. This proposal will result

in total benefits ranging from $3.2 to

$230 million (in 1990 $’s) due to

reduced cancer risks and increased

recreational values of wetlands.

Since the inception of the project in

1994, there have been periodic meetings

with the industry and several trade

associations, including the Louisiana

and Texas Independent Oil and Gas

Associations (TIOGA and LIOGA) and

American Petroleum Institute (API) to

discuss progress on the rulemaking. The

Agency also has met with the Natural

Resources Defense Council (NRDC) to

discuss progress on this rulemaking.

Because all of the facilities affected by

this proposal are direct discharges, the

Agency did not conduct an outreach

survey of POTWs.

The Agency also held a public

meeting on July 19, 1994. The purpose

of the meeting was to present the project

status and discuss the technical options

under consideration for this proposal.

Representatives from industry trade

associations, individual industry

companies, state regulatory authorities,

the U.S. Department of Energy and

Interior (Minerals Management Service)

and the Sierra Club Legal Defense Fund

attended.

The Agency will continue this process

of consulting with state, local, and other

affected parties after proposal in order

to further minimize the potential for

unfunded mandates that may result

from this rule. These proposed

requirements, when promulgated, will

be implemented via the existing

regulatory structure and no additional

burden is expected.

C. The EPA Region VI Coastal Oil and

Gas Production NPDES General Permits

EPA’s Region VI has recently

published final NPDES General permits

regulating produced water and

produced sand discharges to coastal

waters in Louisiana and Texas (60 FR

2387, Jan. 9, 1995). The permits prohibit

the discharge of produced water and

produced sand derived from the coastal

subcategory to any water subject to EPA

jurisdiction under the Clean Water Act.

Much of the industry covered by

today’s proposed rulemaking is also

covered by these General permits.

However, a significant difference

between the permits and this proposal

is that the permits do not cover

produced water discharges derived from

the Offshore subcategory wells into the

main deltaic passes of the Mississippi

River, or to the Atchafalaya River below

Morgan City including Wax Lake Outlet.

The rulemaking being proposed today

would cover these discharges (see the

discussion below entitled ‘‘C.

Preventing the Circumvention of

Effluent Limitations Guidelines and

New Source Performance Standards’’).

Due to the close proximity of the

timing of the publication of the Region

6 permits and this proposal, this

preamble presents the costs and impacts

of today’s rulemaking as if the Region Vi
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9431

General permits were not final. As

presented in later sections of this

preamble, today’s proposal (including

the facilities covered by the Region VI

permit) would remove 4.3 billion

pounds of pollutants in produced water

from being discharged per year. The

Region VI permit covers approximately

71 percent of the produced water

volume being discharged in the coastal

subcategory. The remaining 29 percent

is derived from coastal facilities treating

offshore produced waters and currently

discharging them into main deltaic river

passes in Louisiana, as well as from

other coastal operations in the U.S.

Thus, with the Region VI General

permits final, this rule would actually

result in the removal of 1.25 billion

pounds (29 percent of 4.3 billion

pounds) of pollutants per year from

being discharged into coastal waters.

As also presented in later sections of

this preamble, compliance costs of

today’s rulemaking (including the

facilities covered by the Region VI

permit) total approximately $40.4

million annually. With the Region VI

General permits final, the costs of this

rule would be reduced to approximately

$19.9 million annually.

EPA will more fully incorporate

regulatory effects of the Region VI

General permits upon promulgation of

the final rule.

D. Preventing the Circumvention of

Effluent Limitations Guidelines and

New Source Performance Standards

This rule also proposes a provision

intended to prevent oil and gas facilities

subject to Part 435 of this title from

circumventing the effluent limitations

guidelines, new source performance

standards and pretreatment standards

applicable to those facilities by moving

effluent from one subcategory to another

subcategory. When EPA establishes its

effluent limitations guidelines and

standards, it does so based on a

determination, supported by analyses

contained in the rulemaking record, that

facilities in that subcategory, among

other factors also considered under the

CWA, can technologically and

economically achieve the requirements

of the rule. The purpose of the rule is

not accomplished if facilities move

effluent from a subcategory with more

stringent requirements to a subcategory

with less stringent requirements or if

facilities move effluent from a

subcategory with less stringent

requirements to a subcategory with

more stringent requirements and

discharge effluent at the less stringent

limitations. Until now, EPA has

attempted to prevent this circumvention

in the National Pollution Discharge

Elimination System (NPDES) permits

issued for this industry. EPA believes,

however, that it would enhance the

enforcement of these provisions to

include them as part of the effluent

limitations guidelines, new source

performance standards and pretreatment

standards.

Therefore, this rule proposes to

prohibit oil and gas facilities from

moving effluent from a subcategory with

more stringent requirements to a

subcategory with less stringent

requirements, unless that effluent is

discharged in compliance with the

limitations imposed by the more

stringent subcategory. For example,

facilities could not move produced

water generated from the onshore

subcategory of the oil and gas industry

(which is subject to zero discharge

requirements) to the offshore

subcategory of the oil and gas industry

and dispose of the effluent at the

offshore limitations and standards.

Similarly, this rule proposes to prohibit

facilities from moving produced water

generated from the offshore subcategory

to the coastal or onshore subcategory

and discharging the produced water at

the offshore limitations. (An offshore oil

and gas facility could, however, pipe

produced water to shore for treatment

and return it to offshore waters for

disposal at the offshore limits. Disposal

of such produced water onshore

however, would be subject to zero

discharge.) EPA intends that these

provisions would be applied

prospectively in future NPDES permits.

E. Common Sense Initiative

On August 19, 1994, the

Administrator established the Common

Sense Initiative (CSI) Council in

accordance with the Federal Advisory

Committee Act (U.S.C. Appendix 2,

Section 9 (c)) requirements. A principal

goal of the CSI includes developing

recommendations for optimal

approaches to multimedia controls for

industrial sectors including Petroleum

Refining, Metal Plating and Finishing,

Printing, Electronics and Computers,

Auto Manufacturing, and Iron and Steel

Manufacturing. The following are the

six overall objectives of the CSI

program, as stated in the ‘‘Advisory

Committee Charter.’’

• Regulation. Review existing

regulations for opportunities to get

better environmental results at less cost.

Improve new rules through increased

coordination.

• Pollution Prevention. Actively

promote pollution prevention as the

standard business practice and a central

ethic of environmental protection.

• Recordkeeping and Reporting. Make

it easier to provide, use, and publicly

disseminate relevant pollution and

environmental information.

• Compliance and Enforcement. Find

innovative ways to assist companies

that seek to comply and exceed legal

requirements while consistently

enforcing the law for those that do not

achieve compliance.

• Permitting. Improve permitting so

that it works more efficiently,

encourages innovation, and creates

more opportunities for public

participation.

• Environmental Technology. Give

industry the incentives and flexibility to

develop innovative technologies that

meet and exceed environmental

standards while cutting costs.

The coastal oil and gas extraction

rulemaking effort was not among those

included in the Common Sense

Initiative. However, many oil and gas

producers (mostly large companies)

involved in coastal oil and gas

extraction activities also have refineries.

These companies are projected to incur

costs associated with the requirements

contained in this proposal, however,

these costs are not projected to have an

economic impact at the firm level. The

Agency believes that the CSI objectives

already have been incorporated into the

coastal oil and gas extraction industry

rulemaking, and the Agency intends to

continue to pursue these objectives. The

Agency particularly will focus on

avenues for giving state and local

authorities flexibility in implementing

this rule, and giving the industry

flexibility to develop innovative and

costs effective compliance strategies. In

developing this rule, EPA took

advantage of several opportunities to

gain the involvement of various

stakeholders. Sections III. E, V and X of

this preamble describe consultations

with state and local governments and

other parties including the industry.

EPA has internally coordinated among

relevant program offices in developing

this rule as well. Section XIV describes

related rulemakings that are being

developed by EPA’s Office of Air

Quality, Planning and Standards,

Underground Injection Control Program,

and Spill Prevention, Control and

Countermeasure Program. EPA will be

monitoring these related rulemakings to

assess their collective costs to the

industry. Section VIII of the preamble

describes the non-water quality impacts

this proposed rule would have on other

media including air emissions and solid

waste disposal.
9432 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

III. Background

A. Clean Water Act

1. Statutory Requirements of

Regulations

The objective of the Clean Water Act

(CWA) is to ‘‘restore and maintain the

chemical, physical, and biological

integrity of the Nation’s waters’’. CWA

§ 101(a). To assist in achieving this

objective, EPA issues effluent limitation

guidelines, pretreatment standards, and

new source performance standards for

industrial dischargers. These guidelines

and standards are summarized below:

a. Best Practicable Control Technology

Currently Available (BPT)—Sec.

304(b)(1) of the CWA

BPT effluent limitations guidelines

apply to discharges of conventional,

priority, and non-conventional

pollutants from existing sources. BPT

guidelines are generally based on the

average of the best existing performance

by plants in a category or subcategory.

In establishing BPT, EPA considers the

cost of achieving effluent reductions in

relation to the effluent reduction

benefits, the age of equipment and

facilities, the processes employed,

process changes required, engineering

aspects of the control technologies, nonwater quality environmental impacts

(including energy requirements), and

other factors as the EPA Administrator

deems appropriate. CWA § 304(b)(1)(B).

Where existing performance is

uniformly inadequate, BPT may be

transferred from a different subcategory

or category.

b. Best Conventional Pollutant Control

Technology (BCT)—Sec. 304(b)(4) of the

CWA

The 1977 amendments to the CWA

established BCT as an additional level

of control for discharges of conventional

pollutants from existing industrial point

sources. In addition to other factors

specified in section 304(b)(4)(B), the

CWA requires that BCT limitations be

established in light of a two part ‘‘costreasonableness’’ test. EPA published a

methodology for the development of

BCT limitations which became effective

August 22, 1986 (51 FR 24974, July 9,

1986).

Section 304(a)(4) designates the

following as conventional pollutants:

biochemical oxygen demanding

pollutants (measured as 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).

c. Best Available Technology

Economically Achievable (BAT)—Sec.

304(b)(2) of the CWA

In general, BAT effluent limitations

guidelines represent the best existing

economically achievable performance of

plants in the industrial subcategory or

category. The CWA establishes BAT as

a principal national means of

controlling the direct discharge of toxic

and nonconventional pollutants. The

factors considered in assessing BAT

include the age of equipment and

facilities involved, the process

employed, 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 these factors. An

additional statutory factor considered in

setting BAT is economic achievability

across the subcategory. Generally, the

achievability is determined on the basis

of total costs to the industrial

subcategory and their effect on the

overall industry financial health. As

with BPT, where existing performance

is uniformly inadequate, BAT may be

transferred from a different subcategory

or category. BAT may be based upon

process changes or internal controls,

even when these technologies are not

common industry practice.

d. Best Available Demonstrated Control

Technology For New Sources

(BADCT)—Section 306 of the CWA

NSPS are based on the best available

demonstrated treatment technology and

apply to all pollutants (conventional,

nonconventional, and toxic). New

plants have the opportunity to install

the best and most efficient production

processes and wastewater treatment

technologies. Under NSPS, EPA is to

consider the best demonstrated process

changes, in-plant controls, and end-ofprocess control and treatment

technologies that reduce pollution to the

maximum extent feasible. 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.

e. Pretreatment Standards for Existing

Sources (PSES)—Sec. 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

(POTW). 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 the implementation of

categorical pretreatment standards, are

found at 40 CFR Part 403. Those

regulations contain a definition of passthrough 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.

f. Pretreatment Standards for New

Sources (PSNS)—Sec. 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.

g. Best Management Practices (BMPs)

Section 304(e) of the CWA gives the

Administrator the authority to publish

regulations, in addition to the effluent

limitations guidelines and standards

listed above, to control plant site runoff,

spillage or leaks, sludge or waste

disposal, and drainage from raw

material storage which the

Administrator determines may

contribute significant amounts of

pollutants.

h. CWA Section 304(m) Requirements

Section 304(m) of the CWA requires

EPA to establish schedules for (i)

reviewing and revising existing effluent

limitations guidelines and standards

and (ii) 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 guidelines for several industry

categories, including the coastal oil and

gas 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. Reilly, Civ.

No. 89–2980). On January 31, 1992, the

Court entered a consent decree (the

‘‘304(m) Decree’’), which establishes
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9433

schedules for, among other things,

EPA’s proposal and promulgation of

effluent guidelines for a number of point

source categories, including the Coastal

Oil and Gas Industry. The most recent

Effluent Guidelines Plan was published

in the Federal Register on August 26,

1994 (59 FR 44234). This plan requires,

among other things, that EPA propose

the Coastal Guidelines by January 1995

and promulgate the Guidelines by July

1996.

2. Prior Federal Rulemakings and Other

Notices

Coastal subcategory effluent

limitations were proposed on October

13, 1976 (41 FR 44943). On April 13,

1979 (44 FR 22069) BPT effluent

limitations guidelines were promulgated

for all subcategories under the oil and

gas category, but action on the BAT and

NSPS regulations was deferred. Table 1

presents the 1979 BPT limitations.

TABLE 1.—COASTAL SUBCATEGORY BPT EFFLUENT LIMITATIONS 2

Waste stream Parameter BPT effluent limitation

Produced Water ............................................................................................................ Oil and Grease ................... 72 mg/l Daily Maximum

48 mg/l 30-Day Average.

Drilling Cuttings ............................................................................................................. Free Oil 1 ............................. No Discharge.

Drilling Fluids ................................................................................................................. Free Oil 1 ............................. No Discharge.

Well Treatment Fluids ................................................................................................... Free Oil 1 ............................. No Discharge.

Deck Drainage .............................................................................................................. Free Oil 1 ............................. No Discharge.

Sanitary-M10 ................................................................................................................. Residual Chlorine ............... 1 mg/l (minimum).

Sanitary-M91M .............................................................................................................. Floating Solids .................... No Discharge.

Domestic Wastes .......................................................................................................... Floating Solids .................... No Discharge.

1The free oil ‘‘no discharge’’ limitation is implemented by requiring no oil sheen to be present upon discharge (visual sheen).

2 40 CFR Part 435, Subpart D.

On November 8, 1989, EPA published

a notice of information and request for

comments on the Coastal Oil and Gas

subcategory effluent limitations

guidelines development (54 FR 46919).

The notice presented information

known to date about control and

treatment technologies, applicable to oil

and gas wastes as well as the Agency’s

anticipated approach to effluent

limitations guidelines development for

BAT, BCT, and NSPS. It also solicited

comments on the information presented

as well as the limitations development

approach and requested additional

information where available.

B. Pollution Prevention Act

In the Pollution Prevention Act of

1990 (PPA) (42 U.S.C. 13101 et seq.,

Pub. L. 101–508, November 5, 1990),

Congress declared pollution prevention

the national policy of the United States.

The PPA declares that pollution should

be prevented or reduced whenever

feasible; pollution that cannot be

prevented or reduced should be

recycled or reused in an

environmentally safe manner wherever

feasible; pollution that cannot be

recycled should be treated in an

environmentally safe manner wherever

feasible; and disposal or release into the

environment should be chosen only as

a last resort.

Today’s proposed rules are consistent

with this policy. In fact, for the two

major wastestreams generated by this

industry, EPA is proposing zero

discharge for drilling fluids and

cuttings, as well as zero discharge for

approximately 80 percent of the volume

of produced water. Zero discharge of

wastes is an alternative that prevents

pollution to the maximum extent

possible. As described later in this

notice, development of these proposed

rules focused on pollution-preventing

technologies, such as drilling fluids

closed-loop recycle systems and

produced water injection systems, that

some segments of the industry have

already adopted.

C. Coastal Subcategory Definition

The coastal oil and gas regulations at

40 CFR 435.41(e) currently define the

coastal subcategory as follows:

‘‘(1) any body of water landward of

the territorial seas as defined in 40 CFR

125.1(gg) or (2) any wetlands adjacent to

such waters.’’ Part 125 was revised at 44

FR 32948 (June 7, 1979).

EPA proposes to clarify the ‘‘coastal’’

definition in this rule. First, EPA

intends to revise the regulation to state

that the coastal subcategory would

consist of ‘‘any oil and gas facility

located in or on a water of the United

States landward of the territorial seas.’’

As suggested by the preamble to the

1979 guidelines in discussing the

coastal definition (44 FR 22017; April

13, 1979), EPA intended the subcategory

to cover all facilities located over waters

under CWA jurisdiction, including

adjacent wetlands. Courts have made it

clear that isolated wetlands with an

interstate commerce connection, as well

as adjacent wetlands, are waters of the

United States subject to CWA

jurisdiction. See, e.g., Hoffman Homes,

Inc. v. Administrator 999 F.2d 256 (7th

Cir. 1993). The revised definition would

make it clear that facilities located in or

on isolated wetlands would be

considered to be coastal. This

application of the coastal definition is

consistent with the EPA Region 6 final

general permit for coastal drilling

operations. 58 FR 49126 (September 21,

1993).

In addition, the revised definition

would no longer refer to 40 CFR

125.1(gg). Part 125 was revised at 44 FR

32948 (June 7, 1979) and no longer

exists in the CFR. That provision, when

it did exist, merely cited section 502(8)

of the CWA which defines territorial

seas as ‘‘the belt of seas measured from

the line of ordinary low water along that

portion of the coast which is in direct

contact with the open sea and the line

marking the seaward limit of inland

waters, and extending seaward a

distance of three miles.’’ 40 CFR

125.1(gg) (July 1, 1978). That statutory

definition is still in effect.

Also, EPA would explicitly include in

the definition of ‘‘coastal’’ certain wells

located in the area between the

Chapman line and the inner boundary

of the territorial seas that were

determined to be coastal as a result of

a decision of the U.S. Court of Appeals

for the Fifth Circuit. American

Petroleum Institute v. EPA, 661 F.2d 340

(5th Cir. 1981). The Chapman line is

formed by a series of 40 latitude and

longitude coordinates that roughly

parallel the Louisiana and Texas

coastline to the Mexican border. EPA’s

interim final regulations issued in 1976

(41 FR 44942; October 13, 1976) defined

‘‘coastal’’ to include all land and water

areas landward of the inner boundary of

the territorial seas and eastward of the

point defined by 89 degrees 45 minutes

West Longitude and 29 degrees 46
9434 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

minutes North latitude and continuing

west of that point through the series of

longitude and latitude coordinates (the

Chapman Line) to the point 97 degrees

19 minutes West Longitude and

continuing southward to the U.S.-

Mexican border.) So defined, the coastal

area included areas on the Gulf coast of

Texas and Louisiana. The 1976

boundaries were set to include wells

located in both water and on land

within the geographic area defined as

coastal.

On April 13, 1979 (44 FR 22069), EPA

redefined the coastal subcategory as set

forth at 40 CFR 435.41(e). This new

definition eliminated reference to the

Chapman line, and instead, defined

coastal with respect to a well’s location

over water bodies or wetlands. Under

this definition, certain wells located on

land, but discharging to coastal areas,

were reclassified into the onshore

subcategory and others were reclassified

as stripper wells, depending on their

production rate. The wells that were

classified as onshore were required to

meet zero discharge which is the

standard applicable to onshore facilities.

Industry challenged EPA’s 1979 final

rule. In American Petroleum Institute v.

EPA, 661 F.2d 340, 354-57 (5th Cir.,

1981), the Court held that EPA had

failed to consider adequately the cost to

the reclassified facilities of this

regulatory change. As a result of the

Court’s decision, EPA suspended the

applicability of the onshore subcategory

guidelines (40 CFR 435.30) to the

reclassified wells and to any wells that

came into existence in the affected area

after the issuance of the 1979

redefinition. See 47 FR 31554 (July 21,

1982). Thus, the wells affected by this

suspension are classified as coastal. To

reflect this fact, the definition of coastal

in 40 CFR 453.41(e) would be revised to

include facilities subject to the

suspension.

D. New Source Definition

The definition of ‘‘new source’’ as it

applies to the Offshore Guidelines was

discussed at length in EPA’s 1985

proposal, (50 FR 34617-34619, August

26, 1985) and in EPA’s final rule (58 FR

12456-12458, March 4, 1993). EPA

proposes that this definition would also

apply to the coastal oil and gas industry.

As discussed in the 1985 proposal and

1993 final rule, provisions in the NPDES

regulations define new source (40 CFR

122.2) and establish criteria for a new

source determination (40 CFR

122.29(b)). EPA is proposing special

definitions which are consistent with 40

CFR 122.29 and which provide that 40

CFR 122.2 and 122.29(b) shall apply

‘‘except as otherwise provided in an

applicable new source performance

standard.’’ (See 49 FR 38046, Sept. 26,

1984.)

In summary, for coastal operations a

drilling operation would be a new

source if the drilling rig is drilling a

coastal development well (not an

exploratory well) in a new water area.

Exploratory or development well

drilling from an existing platform or rig

that has not moved since it drilled a

previously existing well would not be a

new source. For production, a new

source would be a facility discharging

from a new site.

EPA invites comments on the

definition of new sources as it applies

to the coastal oil and gas subcategory.

E. Summary of Public Participation

EPA encourages full public

participation in developing the final

Coastal Guidelines. During the data

gathering activities that preceded

development of the proposed rule, EPA

received written comments on the 1989

Notice of Information and Request for

Comments and has met with

representatives from industry and

environmental groups, as well as state

and other federal agencies. To further

public participation on this rule, on July

19, 1994, EPA held a public meeting

about the content and the status of the

proposed regulation. The meeting was

announced in the Federal Register (59

FR 31186; June 17, 1994), and

information packages were distributed

at the meeting. The public meeting also

gave interested parties an opportunity to

provide information, data, and ideas to

EPA on key issues. EPA will assess all

comments and data received at that

public meeting along with comments

and data received as a result of this

proposal as well as the 1989 Notice of

Information, prior to promulgation.

During the development of the

proposed Coastal Guidelines, EPA sent

a questionnaire to industry under

authority of section 308 of the CWA.

During its design, EPA met with

industry trade associations (on March

19, 1992) to discuss its plans to issue a

questionnaire. Following the March

meeting, EPA distributed a draft of the

questionnaire to NRDC, industry

representatives, and trade associations

for review and comment. On May 7,

1992, EPA met with industry

representatives to discuss industry

comments. NRDC did not provide

comments. A final questionnaire was

subsequently completed, reviewed and

approved by the Office of Management

and Budget (OMB) and sent to coastal

oil and gas operators on August 30,

1993.

IV. Description of the Industry

A. Industry Description

Drilling in coastal areas occurs onland

as well as over water or wetlands.

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 involve the use of a circularly

rotating drill bit that grinds through the

earth’s crust as it descends. Drilling

fluids are injected 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. 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.

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 coastal

areas, wells depths range from

approximately 8,000–12,000 feet deep,

and it takes approximately 20–60 days

to complete drilling.

On the surface, the drilling fluid and

drill cuttings undergo an extensive

separation process to remove as much

solids (e.g., cuttings) from the fluid as

possible. The fluid is then recycled into

the system, and the cuttings become a

waste product. 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.

Once the target formations have been

reached, and a determination made as to

which have commercial potential, the

well is made ready for production by a

process termed ‘‘completion’’.

Completion involves cleaning the well

to remove drilling fluids and debris, the

perforation of the casing that lines the

producing formation, insertion of

production tubing to transport the

hydrocarbon fluids to the surface, and

installation of the surface wellhead. The

well is now ready for production, or

actual extraction of hydrocarbons.
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9435

The hydrocarbons extracted from the

well usually consist of a combination of

oil, gas, and brines (produced water).

These fluids are initially directed from

the wellhead to a separation facility

where gas and oil are separated out and

either treated further or sent directly

offsite for sales, and the produced

waters undergo further separation to

remove as much oil as possible from the

water.

The separation facilities, or

production facilities, consist of the

treatment equipment and storage tanks

that process the produced fluids.

Production facilities may be configured

to service one well, or as central

facilities which service multiple

satellite wells, also known as tank

batteries or gathering centers.

Coastal production facilities can be

located over water or on land.

Production facilities located over water

exist in generally two types of

configurations: (1) Individual deep

water multi-well platforms or; (2)

central facilities supported on barges or

wooden or concrete pilings that service

multiple satellite wells in shallow

water. Production facilities on land may

service satellite wells in any

combination of locations. The type of

configuration is an important factor

when examining costs of installing

pollution control equipment.

Multi-well platforms, such as those

found in the Gulf of Mexico offshore

region, are not commonly found in the

coastal region of the Gulf of Mexico.

Based on an earlier mapping effort of all

oil and gas wells, EPA determined that

there are only four structures owned

and operated by four different operators

in the coastal Gulf of Mexico region that

can be classified as multi-well

platforms. However in the Gulf coastal

areas, many single wellheads are located

throughout the coastal waters, serviced

by gathering centers located on-land or

on platforms. Although there are some

exceptions, in most cases those located

on land can be accessed by car or truck

(land-access) while those facilities

located over water must be accessed by

boat or barge (water-access). An analysis

of the EPA 1993 Coastal Oil and Gas

Questionnaire data results indicates that

approximately 34 percent of the

production facilities in the Gulf of

Mexico are land accessed, and 66

percent are water-accessed facilities.

(See Section V.B for description of the

Questionnaire). This distinction is

important when estimating regulatory

compliance costs and impacts as

described in sections VI and VIII. On the

other hand, all coastal structures in

Cook Inlet, Alaska are deep water multiwell platforms, all accessible only by

water (or air) transportation.

Depending on operational preference

or regulatory requirements, many of the

coastal production facilities do not

discharge produced water and thus,

would not incur costs due to this

rulemaking.

B. Location

Coastal oil and gas activities are

located on water bodies inland of the

inner boundary of the territorial seas.

These water bodies include inland

lakes, bays and sounds, as well as

saline, brackish, and freshwater wetland

areas. Although the definition includes

water bodies even in all inland U.S.

states, EPA knows of no existing

operations other than those in certain

states bordering the coast. Thus, at this

time, the coastal oil and gas operations

are located only in coastal states.

Current coastal oil and gas activity

exists along the Gulf of Mexico coastal

states of Texas, Louisiana, Alabama and

Florida, in San Pedro Bay, California

and also in Alaska’s Cook Inlet and the

North Slope areas. The majority of Gulf

Coast activity takes place in Texas and

Louisiana. There, coastal oil and gas

operations exist in a number of

topographical situations including bays,

sounds, lakes, and wetlands. Coastal oil

and gas activity in Alabama is located

in Mobile Bay; and a small number of

wells are also located in wetlands along

the west coast of Florida.

Coastal oil and gas activity in

California exists behind the barrier

island that forms San Pedro Bay (in

Long Beach Harbor). There, four manmade islands have been constructed

solely for the purpose of oil and gas

extraction.

Roughly one third of all the coastal oil

and gas production activity exists in

Alaska. Deep water platforms exist in

the northern part of Cook Inlet. In

addition, operations resembling onshore

activities (as opposed to deep water

platforms) are located on the tundra

wetlands of Alaska’s North Slope.

C. Activity

Table 2 summarizes the number of

producing wells and annual drilling

activities for the coastal subcategory and

the number of producing facilities that

would incur costs (those still

discharging after the projected final date

of July 1996) due to this rulemaking, by

geographic locations.

TABLE 2.—PROFILE OF COASTAL OIL AND GAS INDUSTRY

Coastal location Region

Number

of producing

wells

(1992)

Number

of production

facilities

(1992)

Number

of production

facilities

that

would

incur

costs

under this

rule

Annual

drilling

activity

Number

of operators that

would

incur

costs

under this

rule

Gulf of Mexico ............................................................. TX & LA ..............................

AL, FL .................................

4675

56

853

ND 1

216

0

686

7

122

0

Alaska .......................................................................... Cook Inlet ...........................

North Slope .........................

237

2085

8

12

8

0

8

161

5

0

California ..................................................................... Long Beach Harbor ............ 586 4 0 7 0

Total .................................................................. ........................................ 7639 877 224 869 127

1 Not determined.

Eight hundred and seventy seven

(877) production facilities listed in

Table 1 are currently discharging

produced water in the coastal areas of

Texas (TX), saline and brackish coastal

waters of Louisiana (LA), and the Cook

Inlet of Alaska. All coastal production

facilities in Mississippi (MS), Alabama

(AL), Florida (FL), the North Slope, and

California do not discharge treated

produced water, but rather inject it

either for disposal or for waterflooding.
9436 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

There are no discharges of drilling

fluids and cuttings from coastal

operators except for those in Cook Inlet.

The volumes and locations of discharges

are discussed in more detail in Section

VI. By July 1996, the scheduled date for

promulgation of this rule, EPA estimates

that there will be 216 facilities operated

by 122 operators discharging produced

water. This is based on data obtained

directly from industry, the 1993 Coastal

Oil and Gas Questionnaire, and state

permit records.

D. Waste Streams

The primary wastewater sources from

the exploration and development phases

of the coastal oil and gas extraction

industry include the following:

• Drilling fluids.

• Drill cuttings.

• Sanitary wastes.

• Deck drainage.

• Domestic wastes.

The primary wastewater sources from

the production phase of the industry

include the following:

• Produced water.

• Produced sand.

• Well treatment, workover, and

completion fluids.

• Deck drainage.

• Domestic wastes.

• Sanitary wastes.

Drilling fluids and drill cuttings are

the most significant waste streams from

exploratory and development operations

in terms of volume and pollutants.

Produced water is the largest waste

stream from production activities in

terms of volumes of discharged and

quantity of pollutants. Deck drainage,

sanitary wastes, domestic wastes,

produced sand, and well treatment,

completion, and workover fluids are

often classified under the term

miscellaneous wastes.

A summary of the sources and

characteristics of each of these wastes is

presented in Section VI of this notice.

Detailed discussions of the origins and

characteristics of the waste water

effluents from exploration,

development, and production are

included in the Coastal Technical

Development Document. EPA has

primarily focused data gathering efforts

and data analyses on drilling fluids,

drill cuttings, and produced water due

to their volumes and potential toxicity.

Information on the other waste streams

discussed above is more limited. Their

volumes are generally smaller, and in

most cases are either infrequently

discharged or are commingled with the

major waste streams. However, EPA has

determined that it is appropriate to

propose regulations for these wastes as

well.

E. Current NPDES Permits

Discharges from coastal oil and gas

operations in the Gulf of Mexico,

California, and Alaska are regulated by

general and individual NPDES permits

based on BPT, State Water Quality

Standards, and on Best Professional

Judgment (BPJ) of BCT and BAT levels

of control. Table 3 lists the requirements

in these permits.

EPA’s Region VI has developed

general NPDES permits for each phase

of oil and gas operations (drilling and

production). The drilling permits for

Louisiana and Texas were proposed in

1990 and a final permits published on

September 21, 1993 (58 FR 49126).

Region VI proposed general production

permits on December 22, 1992 (57 FR

60926), and final permits on January 9,

1995 (60 FR 2387).

EPA’s Region X issued a BPT and BPJ

general NPDES permit for oil and gas

operations in the Upper Cook Inlet.

However, although expired, conditions

of this general permit are still fully

effective and enforceable until the

permit is reissued. Region X is currently

in the process of reissuing the BPT and

BPJ/BAT general permit for this area

with proposal expected in early 1995. In

addition to the general permit, the

Region issued an individual permit

regulating discharges from exploratory

drilling operations in Upper Cook Inlet

in May 1993. The individual permit was

also based on BPT and BPJ/BAT.

The State of Alabama, which has been

authorized to administer the NPDES

program, has also issued a final NPDES

general permit covering facilities in

state waters, including offshore and

coastal facilities (including Mobile Bay).

(Permit #ALG280000, May 25, 1994).

This permit specifically prohibits the

discharge of drilling fluids and cuttings,

and produced water. The permit also

does not allow the discharge of

produced sands or treatment, workover

and completion fluids.

Regional permit requirements are

based on other factors, in addition to

technology pollutant removal

performance, including water quality

criteria.

TABLE 3.—NPDES PERMIT REQUIREMENTS 1

[Regional Permit Requirements]

Wastestream Region X (Cl 1986 BPT permit)

Region X exploration permit

(1993)

Region VI final

drilling permit

(1993)

Region VI

production

permit (final)

(1995)

Region IV permit

(1994)

Produced Water ...... Monitor daily flow rate Oil &

Grease: Phillips A Platform

20 mg/l daily max 15 mg/l

mo. ave. Other facilities: 48/

72 mg/l pH=6-9.

Not applicable ......................... Covered in Production Permit.No Discharge No Discharge.

Produced Sand ........ No free oil (Static Sheen) ....... Not applicable ......................... Not applicable ..... No Discharge No Discharge.

Drilling Fluids and

Cuttings.

(1) Toxicity: Discharge only

approved generic muds.

(1) Flowrate = 750 bbl/hr ........ No Discharge ...... Not applicable.No Discharge.

(2) No free oil- static sheen ... (2) Use authorized muds only.

(3) No discharge oil-based

muds.

(3) Toxicity: 30,000 ppm in

SPP.

(4) 10 percent oil content for

cuttings.

(4) No free oil.

(5) No diesel oil ...................... (5) No discharge of oil-based

fluids.

(6) 1/3 mg/kg Hg/Cd in dry

barite.

(6) 5 percent (wt) oil content

in cuttings.

(7) Flow rate ........................... (7) No discharge of diesel oil.

>40m = 1000 bbl/hr ............ (8) 1 mg/kg Hg and 3 mg/kg

Cd in stock barite.
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9437

TABLE 3.—NPDES PERMIT REQUIREMENTS 1—Continued

[Regional Permit Requirements]

Wastestream Region X (Cl 1986 BPT permit)

Region X exploration permit

(1993)

Region VI final

drilling permit

(1993)

Region VI

production

permit (final)

(1995)

Region IV permit

(1994)

>20-40m = 750 bbl/hr.

>5-20m = 500 bbl/hr.

<5m = No discharge.

‘‘Dewatering Effluent’’.Not separately regulated ........ Not separately regulated No free oil ........... Not applicable.Not separately

regulated.

50 mg/l TSS.

125 mg/l COD pH

= 6-9.

500 mg/l chlorides.

0.5 mg/l total Cr.

5.0 mg/l Zn Monitor volume.

Treatment, Completion, Workover

Fluids.

No free oil (Static Sheen) .......

No oil-based fluids ..................

pH = 6-9 .................................

Oil and grease limits apply to

combined discharge of any

TWC commingled with produced water ........................

No discharge of free oil or oilbased fluids.

Monitor frequency of discharge and volume pH =

6.5–8.5.

Oil & grease = 72 daily max.

& 48 mo. avg ......................

Freshwater: No

discharge.

Saline water: No

toxics, No free

oil (visual

sheen), pH = 6-

9

Not applicable.No Discharge.

Domestic Wastes .... No free oil (No visible sheen) . Monitor flow rate ..................... No discharge of

solids (‘‘garbage’’).

Not applicable.Flow = 10,000

gpd max.

No Floating solids ................... No free oil (No visible sheen) . BOD5 = 45 mg/l

daily max.

Monitor flow rate ..................... No floating solids .................... = 30 mg/l

No visible foam ....................... (mo. aver.)

TSS = 45 mg/l

daily max.

= 30 mg/l

(mo. aver.)

Total residual

chlorine = 1.0

mg/l (daily min)

maintained as

close to this

value as possible.

No Floating Solids.

Deck Drainage ......... No free oil (Visual Sheen)

Monitor flow rate (mo. ave.).

Monitor flow rate (mo. avg.)

No free oil (visual sheen).

No free oil (visual

sheen) Monitor

volume.

Not applicable.Monitor daily flow

No free oil (visual

sheen)

Sanitary Wastes ...... No floating solids .................... No free oil (No visible sheen) . No floating solids Not applicable.Flow = 10,000

gpd max.

As close as possible to, but

no less than 1.0 mg/l.

No floating solids .................... BOD = 45 mg/l .... BOD5 = 45 mg/l

daily max.

BOD & SS2 ............................ No visible foam ....................... TSS = 45 mg/l

fecal coliforms

= 200/100 mls

Monitor flow.

= 30 mg/l (mo.

aver.)

TSS = 45 mg/l

daily max.

= 30 mg/l (mo.

aver.)

Total residual

chlorine = 1.0

mg/l (daily min)

maintained as

close to this

value as possible.

No Floating Solids.

24 hr = 60 mg/l ................... As close as possible but no

less than 1 mg/l.

7 day = 45 mg/l ................... BOD: 30 day=30 mg/l.
9438 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

1The term ‘‘major’’ oil and gas company is used

here to differentiate it from smaller operators in the

industry. Major oil and gas companies are

characterized by a high degree of vertical

integration, i.e., their activities encompass both

‘‘upstream’’ activities—oil exploration,

development, and production and ‘‘downstream’’

activities—transportation, refining, and marketing.

As a group the majors generally produce more oil

and gas, earn significantly more revenue and

income, have considerably larger assets, and have

greater financial resources than the independent

operators.

TABLE 3.—NPDES PERMIT REQUIREMENTS 1—Continued

[Regional Permit Requirements]

Wastestream Region X (Cl 1986 BPT permit)

Region X exploration permit

(1993)

Region VI final

drilling permit

(1993)

Region VI

production

permit (final)

(1995)

Region IV permit

(1994)

30 day = 30 mg/l ................. 24 hr = 60 mg/l .......................

TSS: 30 day = TSS intake +

30 mg/l.

24 hr = TSS intake + 60

mg/l .....................................

1For a complete presentation of the effluent limitations and their bases in the permits see the following: Region X Proposed General Permit for

Cook Inlet: 50 FR 28974, 7/17/85, Region X Final Permit for Cook Inlet: 51 FR 35460, 10/3/86, Region VI Final General Permit for Drilling Operations: 58 FR 49126, 9/21/93, Region VI Proposed General Permit for Production Operations: 57 FR 60926, 12/22/92. The Region X Exploration

Permit and the Region IV Permit are in the record for this rulemaking. 2 Limits apply only to discharges to state waters and separately for BOD and SS.

V. Summary of Data Gathering Efforts

The major studies presenting

information on coastal oil and gas

effluents and treatment technologies

which have bearing on this proposed

rule are summarized in this section.

These investigations include:

underground injection of produced

water and associated produced water

treatment technologies; solids control

technologies for drilling fluids; drilling

fluids and drill cuttings waste

generation, treatment, and disposal in

coastal Alaska; and commercial nonhazardous oil and gas waste disposal

facilities and technologies. In addition,

EPA sent a CWA section 308

Questionnaire to the industry to gather

information characterizing coastal oil

and gas pollution control technology

and the costs of such technologies. The

questionnaire and results are described

below.

A. Information Used From the Offshore

Guidelines

Due to certain similarities in the

technologies employed and wastes

generated by the offshore and coastal

subcategories of the oil and gas

industry, certain data generated during

the Offshore Guidelines development

effort have been utilized in the

development of this proposed rule

where appropriate. Those data most

influential in the development of this

proposed rule, listed below, are

summarized both in the Coastal

Technical Development Document and

described in more detail in the

Development Document for the Effluent

Limitations Guidelines and New Source

Performance Standards for the Offshore

Subcategory of the Oil and Gas

Extraction Point Source Category,

(hereafter referred to as the Offshore

Technical Development Document),

Sections V and XVIII (EPA, January

1993).

• Produced water characteristics for

Cook Inlet.

• Produced water characteristics for

effluent from improved gas flotation.

• Drilling fluids and cuttings waste

characteristics.

• Deck drainage characteristics.

• Domestic waste characteristics.

• Sanitary waste characteristics.

• Some non-water quality

environmental impacts.

B. 1993 Coastal Oil and Gas

Questionnaire

A comprehensive questionnaire

entitled the ‘‘1993 Coastal Oil and Gas

308 Questionnaire’’ was developed

under the authority of section 308 of the

CWA. EPA distributed this

questionnaire to all known coastal oil

and gas operators. The Questionnaire

requested information on oil and gas

waste generated, their treatment and

disposal methods and costs for waste

treatment and disposal. The

questionnaire also requested

information regarding the financial

profile of each operator surveyed.

Upon their return, EPA reviewed the

questionnaires for completeness and

technical content and then transcribed

the responses into a computer readable

format using double key-entry

procedures. EPA prepared statistical

estimates in order to extrapolate the

results from the sampled wells and

facilities to the entire coastal industry.

EPA used the individual data and the

statistical reports to determine waste

volumes, treatment and disposal

methods and costs of treatment and

disposal methods. EPA also used the

survey results to estimate future

industrial activity. The statistical

analysis of the questionnaire data is

included in the record for this

rulemaking.

C. Investigation of Solids Control

Technologies for Drilling Fluids

In 1993, EPA collected samples and

gathered technical data at three drilling

operations in the coastal region of

Louisiana. The purpose of this effort

was to gather operating and cost

information regarding closed-loop solids

control technology (See description of

this technology in Section VI.A) at

active oil and gas well drilling

operations. Two of the sites were

drilling using land-based rigs, and the

other operation was located in an inland

bay and used a posted barge rig. One

operator was a large independent, the

other 2 were majors.1

Technical and cost information was

collected on the following topics:

• Drilling waste volumes and

disposal methods.

• Solids control equipment design

and performance.

• Drilling fluids.

• Well design and construction.

• Drilling operations.

• Annular injection.

• Miscellaneous waste volumes and

disposal methods.

EPA used the results of this

investigation to determine methods and

costs of drilling waste disposal, as well

as miscellaneous waste volumes, and

their treatment and disposal.

D. Sampling Visits to 10 Gulf of Mexico

Coastal Production Facilities

EPA visited ten coastal oil and gas

production facilities located in Texas
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9439

and Louisiana to gather operating and

cost information regarding produced

water injection and to collect samples of

produced water and miscellaneous

wastes. Samples were analyzed for a

variety of analytes in the categories of

organic chemicals, metals, conventional

and non-conventional pollutants, and

radionuclides. Sampling at each site

was conducted for one day over a span

of eight hours. Technical and cost data

were collected in addition to the

production waste samples.

EPA was careful, in its selection of

Gulf Coast sites, to visit facilities that (1)

were located in both Texas and

Louisiana, (2) were located in different

wetland situations (wetlands, or inland

bays), and (3) that ranged in operator

size (major to small independent). Nine

of the ten facilities visited utilized

injection wells for produced water

disposal and one utilized surface

discharge.

A focus of this site visit program was

to investigate the technologies used to

treat produced waters prior to injection.

Several of the facilities employed

cartridge filtration subsequent to BPT

treatment (gravity separation sometimes

assisted by heat or chemicals).

Aqueous samples were collected from

settling tank effluent at all ten facilities,

as well as the influent (settling effluent)

and effluent of all four filtration

systems. Samples were analyzed for the

following analytes:

—TSS

—Oil and Grease

—Volatile Organics

—Semi-volatile Organics

—Metals

—Conventional Parameters

—Non-conventional Parameters

—Radionuclides

Cartridge filters were also collected at

all the facilities that utilized them, and

were analyzed for radionuclides

concentrations. Samples of produced

sands were also collected where

available and analyzed for the same

pollutants as for produced water.

In addition to the sampling activities,

technical and cost information was

collected on the following topics:

• Separator and treatment system

technologies and configuration.

• Equipment space requirements.

• Support structures.

• Miscellaneous waste volumes

treatment and disposal methods.

• Produced water volumes and

disposal methods.

• Energy requirements.

• Injection well remedial work

requirements.

• Ancillary equipment requirements

(besides the injection well) for injection.

• Injection well design and operation.

• Production data.

The results from this study, together

with data from the EPA 1993 Coastal Oil

and Gas Questionnaire and state permit

data, discussed below, formed the basis

for EPA’s produced water treatment and

disposal cost analyses discussed later in

Section VI.B. The analytical data was

used to characterize produced water

effluent characteristics from BPT

treatment systems.

E. State Discharge Monitoring Reports

EPA obtained detailed information on

produced water discharges from state

discharge permits for operators in Texas

and Louisiana. The Louisiana

Department of Environmental Quality

(LADEQ) and the Texas Railroad

Commission (TRC) supplied EPA with

state permits for all known dischargers

in the coastal areas. The state permit

information identifies the operator, the

name of the producing field, the

location of the production facility, the

volume of produced water discharged,

the location and permit number of the

outfall, and in Louisiana only, the

compliance date by which the discharge

must cease. From these data, EPA

estimated that 216 production facilities

in both the Texas and Louisiana coastal

region will be discharging after July

1996 (the projected date of issuance of

this regulation). The list of these

facilities is presented in the record for

the rulemaking. From this list EPA

estimated costs of produced water

treatment and disposal on a per facility

basis.

F. Commercial Disposal Operations

In May 1992, EPA visited two non

hazardous oil and gas waste land

treatment facilities and two waste

transfer stations in Louisiana. The

purpose of these visits was to

investigate the transportation, handling,

disposal methods employed and

associated costs of these operations.

Detailed information was gathered

concerning the operation of the

landfarm treatment process used for the

disposal of non-hazardous oil field

wastes, transportation equipment,

transfer equipment, equipment fuel

requirements and costs incurred by the

facilities and costs charged to the

customers. The information was used in

the development of compliance costs

and the non-water quality

environmental impacts for the various

regulatory options under consideration.

In March 1992, EPA visited two

commercial produced water injection

facilities in Louisiana. The purpose of

the visits was to collect information

regarding costs of produced water

disposal and other operating costs as

well as to collect samples of produced

water, filter solids, used filters and tank

bottoms solids for radioactivity analysis.

Both facilities utilized sedimentation

and filtration as treatment processes for

produced water followed by

underground injection. The technical

information gathered at these sites was

used in developing compliance costs

and the non-water quality impacts for

the various regulatory options under

consideration. The results of the

radioactivity analyses were used in an

evaluation of radioactivity

concentrations in oil and gas wastes.

G. Evaluation of NORM in Produced

Waters

EPA reviewed all known data

regarding the presence of naturally

occurring radioactive materials (NORM)

found in discharge of produced water

and associated with scales and sludges

on oil and gas production equipment.

EPA summarized produced water

radioactivity data from 22 available

studies focusing on data from coastal

sites. Each of these 22 studies was

summarized according to the location of

the sites, sampling plans, and analytical

methods used to measure the

radionuclides. This information was

used in characterizing NORM in

produced water discharges in the Gulf

Coast.

H. Alaska Operation

In August 1993, EPA embarked on a

fact-finding mission regarding drilling

and production operations and practices

in both regions of Alaska, Cook Inlet

and the North Slope. Information and

data were obtained by direct visits to

these areas, and by contacting the

Alaska Oil and Gas Association

(AOGA), state regulatory authorities,

and individual operators. In addition,

AOGA and individual operators

submitted to EPA information on

projects and technologies currently

being developed and used in Cook Inlet

and on the North Slope to dispose of

drilling and production wastes, and the

costs associated with these projects.

Specific operating and cost information

was obtained on zero discharge

technologies including grinding and

injection systems for drilling fluids and

drill cuttings as well as produced water

injection. EPA used the information

obtained during this data gathering

effort to estimate costs of treatment and

control options for Alaska coastal

facilities.

In March 1994, Cook Inlet Alaska oil

and gas operators submitted to EPA

information on drilling waste disposal

alternatives and their costs and on
9440 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

projected drilling schedules. Three

alternatives were evaluated by the

operators in terms of technological

achievability and costs: discharge to

Cook Inlet surface water, land-based

disposal, and disposal by injection. EPA

considered this information during its

development of regulatory options and

estimation of costs for disposal of

drilling wastes in Cook Inlet. These

same Cook Inlet operators also

submitted to EPA information on the

technological and economic feasibility

of zero discharge of produced water

from the largest shore-based production

facility in the Inlet. This information

presented the costs and technological

achievability for three produced water

injection alternatives including (1)

Treatment and injection at the

platforms, (2) treatment at onshore

treatment facilities (for some platform

operations) and onshore injection, and

(3) treatment at onshore treatment

facilities and injection back at the

platforms. EPA considered this

information during its development of

zero discharge option for produced

water and cost estimations in Cook

Inlet.

I. Region X Drilling Fluid Toxicity Data

Study

EPA evaluated a summary data base

containing Region X permit compliance

monitoring information including

toxicity measurements of drilling fluids

used in Alaska. The database contains

161 records of 96-hour LC50 data from

coastal and offshore oil and gas wells in

Alaska from 1985 to 1994. Drilling fluid

toxicity levels were characterized for

Alaska drilling activities, and

particularly for activities in Cook Inlet.

This data indicated that drilling fluids

and cuttings being discharged in Cook

Inlet may be able to meet a toxicity

limitation of between 100,000 ppm

(SPP) and 1,000,000 ppm (SPP).

EPA measures toxicity using a

standard bioassay test known as the

‘‘Drilling Fluids Toxicity Test’’ (See 40

CFR 435 Subpart A, Appendix 2). Under

this test, the species mysidopsis bahia is

exposed to different concentrations of

the drilling fluids and cuttings for a set

time, 96 hours. An LC–50 toxicity test

is performed by mixing a solution of

seawater and drilling fluids and

cuttings, allowing the solution to settle

for one hour, decanting the liquid off

from the settled solids, and then adding

to the decant, or suspended particulate

phase (SPP), the test organisms and

determining the number of organisms

alive after 96 hours. Then, by observing

mortality rates and by calculation, the

concentration required to kill 50 percent

of the test animals in 96 hours is

determined. The ‘‘96-hour LC–50’’ is

defined as the lethal concentration of a

toxicant that will kill 50 percent of the

test organisms after a 96-hour exposure.

Thus, the lower the LC–50 value, the

higher the relative toxicity.

J. California Operations

EPA visited coastal oil and gas

operations in Long Beach Harbor,

California in February 1992. The visit

was to one of the four man-made islands

that have been constructed in the

Harbor for the purpose of oil and gas

extraction. The facilities on these

islands are operated by THUMS, a

consortium of five oil and gas operating

companies (Texaco, Humble (now

Exxon), Union, Mobil and Shell). EPA

met with state regulatory officials and

was given a tour of one of the islands

by THUMS personnel. Both drilling and

production were occurring at the time of

the visit.

Information regarding waste

generation, treatment, disposal, and

costs were obtained during the visit. No

discharges are occurring from the

THUMS operations. The information

provided EPA with specific waste

disposal technology and cost

information which has, where

appropriate, been incorporated into cost

analyses, and enabled EPA to

characterize California coastal oil and

gas operations.

K. OSW Sampling Program

EPA’s Office of Solid Waste

conducted a sampling program on

associated oil and gas wastes in 1992.

As part of this effort, samples were

obtained for completion, workover, and

treatment fluids. The parameters

analyzed for were the same as those for

produced water samples listed

previously in Section V.D. EPA has used

this data base to characterize the

discharges of these fluids. Seven

samples of treatment, workover and

completion fluids were collected from

operations in Texas, New Mexico and

Oklahoma. The samples were analyzed

for conventional, nonconventional and

priority pollutants.

L. Estimation of the Inner Boundary of

the Territorial Seas

As part of the Coastal Guidelines

development effort, EPA specifically

delineated the seaward boundary of the

coastal subcategory (which is the inner

boundary of the Territorial Seas). The

purpose of this effort was to define an

area in order to estimate the number of

coastal wells and production facilities

operating in that area. The purpose was

not to determine a well’s subcategory for

regulatory permit writers. This

delineation is in the form of latitude and

longitude coordinates covering that part

of the inner boundary of the Territorial

Seas along Alaska’s North Slope and

Cook Inlet, Texas, Louisiana, Alabama

and Southern California. Much of this

boundary has been delineated on

nautical charts published by the

National Ocean Service of the National

Oceanic and Atmospheric

Administration (NOAA). In some

locations however, this boundary has

not previously been delineated by

NOAA, and EPA completed the

coordinates using established

procedures described in the Convention

of the Territorial Seas and the

Contiguous Zone, Articles 3–13. The

digital coordinates of the inner

boundary of the Territorial Seas, for the

above mentioned locations and a

description of its derivation is included

in the record for this rule. This digital

boundary assisted EPA in its

determination of the number of wells

and production facilities that exist in

this subcategory.

VI. Development of Effluent Limitations

Guidelines and Standards

A. Drilling Fluids and Drill Cuttings

(Drilling Wastes)

1. Waste Characterization

Drilling fluid and cuttings discharges

are typically generated in bulk form and

occur intermittently during well drilling

and at the end of the drilling phase.

There are currently no drilling fluids

and cuttings discharges in any coastal

area except Cook Inlet. In Cook Inlet,

operators do not currently practice zero

discharge, except for a small volume of

drilling fluids and cuttings wastes

(approximately one percent) which are

not discharged because they do not meet

current permit limits. Generally, drilling

fluids and cuttings volumes average

approximately 14,000 barrels (bbl) per

new well drilled in Cook Inlet. (NOTE:

The barrel is a standard oil and gas

measurement and is equal in volume to

42 gallons). Based on industry

projections given to EPA, an average of

79,000 bbls drilling fluids and cuttings

are generated each year (bpy) in the

Inlet. Significant pollutants in these

wastes include chromium, copper, lead,

nickel, selenium, silver, beryllium and

arsenic among the toxic metals. Toxic

organics present include naphthalene,

fluorene, and phenanthrene.

TSS makes up the bulk of the

pollutant loadings, part of which is

comprised of the toxic pollutants. TSS

concentrations are very high due to the

nature of the wastes. And because its

TSS concentration is so high, discharges

of drilling fluids and cuttings can cause
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9441

reduced light penetration resulting in

decreased sea life primary productivity,

fish kills or reduced growth rate,

interference in development of fish eggs

and larvae, modifications of fish

movement and migration, and reduction

of the abundance of food available to

fish. Benthic smothering from settleable

materials results in potential damage to

invertebrate populations and potential

alterations in spawning grounds and

feeding habitats.

Operators use solids control

equipment to remove drill cuttings from

the drilling fluid systems which allows

drilling fluids to be recycled and

reduces the total amount of drilling

wastes generated. Depending on the

drilling solids control system and the

method of waste storage and disposal

onsite, a small wastestream, termed

‘‘dewatering effluent’’ may be segregated

from the drilling fluids and cuttings.

Dewatering effluent may be discharged

from reserve pits or tanks which store

drilling wastes for reuse or disposal.

Dewatering effluent may also be

generated in enhanced solids control

systems. Enhanced solids control

systems, also known as closed-loop

solids control operations, remove solids

from the drilling fluid at greater

efficiencies than conventional solids

removal systems. Increased solids

removal efficiency minimizes the

buildup of drilled solids in the drilling

fluid system, and allows a greater

percentage of drilling fluid to be

recycled. Smaller volumes of new or

freshly made fluids are required as a

result. An added benefit of the closedloop technology is that the amount of

waste drilling fluids can be significantly

reduced. The installation of reserve pits

is unnecessary in closed-loop systems

for this reason. Dewatering effluent is

generated in the process of drilling

fluids solids removal and can either be

reused (it often contains expensive

reusable chemicals), or disposed of.

EPA’s general permit for drilling

operations for TX and LA included

limitations for the discharge of

dewatering effluent (See Section VI.E).

However, the 1993 Coastal Oil and Gas

Questionnaire results show that few

operators discharge dewatering effluent

as a separate wastestream. Additionally,

contacts with industry indicate that the

volume of dewatering effluent from

reserve pits is small if nonexistent as the

use of pits is phasing out due to state

permit conditions, environmental or

land owner concern, or the expanding

use of closed-loop systems. EPA site

visits to drilling operations, where these

closed-loop systems were in place,

showed that none of the dewatering

effluent was discharged. Instead, it is

either recycled, or sent with other

drilling wastes to commercial disposal.

Operators at these facilities explained

that it is less expensive to send this

wastestream along with drilling fluids

and drill cuttings for onshore disposal

rather than to treat for discharge.

2. Selection of Pollutant Parameters

a. Pollutants Regulated

In the coastal subcategory, EPA is

proposing to establish BAT, NSPS, and

pretreatment standards that would

require zero discharge of drilling fluids

and drill cuttings. Where zero discharge

is required, EPA would be controlling

all pollutants in the wastestream.

EPA is also considering an alternative

BAT limit applicable only to Cook Inlet,

that in addition to the BPT requirement

prohibiting the discharge of free oil,

would also prohibit the discharge of

diesel oil and limit toxicity and specify

the cadmium and mercury content in

stock barite. As presented in Section VI

of the Offshore Technical Development

Document, the prohibitions on the

discharge of free oil and diesel oil

would effectively remove toxic,

nonconventional, and conventional

pollutants. Diesel oil and free oil are

considered, under BAT and NSPS, to be

‘‘indicators’’ for the control of specific

toxic pollutants present in the complex

hydrocarbon mixtures used in drilling

fluid systems. These pollutants include

benzene, toluene, ethylbenzene,

naphthalene, phenanthrene, and

phenol. Additionally, diesel oil may

contain from 20 to 60 percent by volume

polynuclear aromatic hydrocarbons

(PAH’s) which constitute the more toxic

components of petroleum products.

Control of diesel oil would also result

in the control of nonconventional

pollutants under BAT and NSPS. Diesel

oil contains a number of

nonconventional pollutants, including

PAHs such as methylnaphthalene,

methylphenanthrene, and other

alkylated forms of the listed organic

priority pollutants.

EPA is proposing to establish BCT

limitations for drill fluids and drill

cuttings that would prohibit discharge

of free oil (using the static sheen test) for

Cook Inlet, and would require zero

discharge everywhere else. The

prohibition on the discharge of free oil

(in addition to the zero discharge

requirement) would effectively reduce

or eliminate the oil and grease in these

discharges. EPA is limiting free oil

under BCT as a surrogate for oil and

grease in recognition of the complex

nature of the oils present in drilling

fluids, including crude oil from the

formation being drilled.

Prohibiting the discharge of diesel oil

and free oil eliminates discharges of the

above-listed constituents, to the extent

that these constituents are present in

either of these two parameters, and

reduces the level of oil and grease

present in the discharged drilling fluids

and cuttings. Also under this alternative

option, limitations on cadmium and

mercury content in barite would control

toxic and nonconventional pollutants in

drilling fluids and cuttings discharges.

This limitation would indirectly 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 the Offshore

Technical Development Document in

Section VI).

Toxicity of drilling fluids and cuttings

is being regulated as a nonconventional

pollutant that controls certain toxic and

nonconventional pollutants. It has been

shown, during EPA’s development of

the Offshore Guidelines, that control of

toxicity encourages the use of less toxic,

water-based drilling fluids, and where

absolutely necessary, the use of less

mineral oil added to a drilling fluid (and

the pollutants, such as the PAH’s,

identified as constituents of mineral

oil). A toxicity limitation would thus

encourage the use of the lowest toxicity

drilling fluids and the use of lowtoxicity drilling fluid additives.

b. Pollutants Not Regulated.

Where zero discharge would be

required, all pollutants would be

controlled in drilling fluids and cuttings

discharges. Where discharges with

limitations would be required,

(specifically if EPA selected the

alternative BAT option in Cook Inlet),

EPA has determined that it is not

technically feasible to specifically

control each of the toxic constituents of

drilling fluids and cuttings that are

controlled by the limits on the

pollutants proposed for regulation.

EPA has determined that certain of

the toxic and nonconventional

pollutants are not controlled by the

limitations on diesel oil, free oil,

toxicity, and mercury and cadmium in

stock barite. EPA exercised its

discretion not to regulate these

pollutants because EPA did not detect

these pollutants in more than a very few

of the samples from EPA’s field

sampling program and does not believe

them to be found throughout the
9442 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

industry; the pollutants when found are

present in trace amounts not likely to

cause toxic effects; and due to the large

number and variation in additives or

specialty chemicals that are only used

intermittently and at a wide variety of

drilling locations, it is not feasible to set

limitations on specific compounds

contained in additives or specialty

chemicals.

3. Control and Treatment Technologies

a. Current Practice.

BPT effluent limitations guidelines for

coastal drilling fluids and drill cuttings

prohibit the discharge of free oil (using

the visual sheen test). However, because

of either EPA general permits, state

requirements, or operational preference,

no drilling fluids and cuttings

discharges are occurring in the North

Slope, the Gulf coast states, or

California. The only coastal operators

discharging drilling fluids and cuttings

are located in Cook Inlet. In Cook Inlet,

neither diesel nor mineral-oil-based

drilling fluids or resultant cuttings may

be discharged to surface waters because

they have been shown to cause a visible

sheen upon the receiving waters.

Compliance with the BPT limitations

may be achieved either by product

substitution (substituting a water-based

fluid for an oil-based fluid), recycle and/

or reuse of the drilling fluid, or by

onshore disposal of the drilling fluids

and cuttings at an approved facility.

NPDES permits issued by EPA for

Cook Inlet drilling operations have also

included BAT limitations based on

‘‘best professional judgement’’ (BPJ).

The permit requirements allow

discharges of drilling fluids and drill

cuttings provided certain limitations are

met including a prohibition on the

discharges of free oil and diesel oil, as

well as limitations on mercury,

cadmium, toxicity and oil content. (See

Section IV.E for a summary of the

permits). Operators may employ any

number of the following waste

management practices to meet those

permit limitations:

* Product substitution—to meet

prohibitions on free oil and diesel oil

discharges, as well as the toxicity and/

or clean barite limitations,

* Onshore treatment and/or disposal

of drilling fluids and drill cuttings that

do not meet the toxicity or clean barite

limitations,

* Waste minimization—enhanced

solids control to reduce the overall

volume of drilling fluids and drill

cuttings, and

* Conservation and recycling/reuse of

drilling fluids.

Refer to the Coastal Technical

Development Document, Sections VIIVIII for a detailed discussion of each of

these waste minimization techniques.

b. Additional Technologies

Considered.

EPA has evaluated an additional

method for drilling fluid and cuttings

control and treatment in order to

achieve zero discharge: namely,

grinding and injection of drilling

wastes. This process involves the

grinding of the drilling fluids and drill

cuttings into a slurry that can be

injected into a dedicated disposal well.

The grinding system consists of a

vibrating ball mill which pulverizes the

cuttings and creates an injectable slurry.

Recent information has shown that this

comparatively contemporary technology

has been successfully demonstrated on

the North Slope for drilling waste

disposal, and is being introduced both

in the Gulf Coast coastal areas as well

as in Cook Inlet. EPA, therefore believes

that this technology is available to

coastal operators.

In addition to grinding and injection,

EPA has also investigated the feasibility

of onshore disposal of this wastestream.

For the coastal subcategory drilling

activities, in areas other than Cook Inlet,

current permits or practice (in the case

of the North Slope) require zero

discharge of drilling fluids and cuttings.

On-land disposal sites located in Alaska

are available in these areas and are

being utilized to comply with the zero

discharge requirement. On-land

disposal sites are also available to two

out of the five Cook Inlet operators.

These two operators jointly operate an

oil and gas landfill disposal site on the

west side of the Inlet. Using projected

drilling schedules provided by industry,

EPA estimated that these two operators

would generate approximately 76

percent of the drilling wastes produced

by the Cook Inlet operators over the next

seven years following the scheduled

1996 promulgation of this rule. EPA has

determined that there is sufficient onland disposal capacity to accept all of

the drilling fluids and cuttings

generated by these two operators at this

disposal facility.

EPA investigated the logistical

difficulties of storing and transporting

drilling wastes in the Cook Inlet, due to

the extensive tidal fluctuations, strong

currents, and ice formation during

winter months. While these

climatological and tidal situations may

cause complications, EPA has

determined that they do not pose

insurmountable technical barriers. EPA

has taken into consideration

supplementary costs incurred by

additional winter transportation and

storage of drilling wastes in its cost

evaluation of the zero discharge

requirement as described later in

Section VI.A.

No on-land oil and gas waste disposal

facilities are available in Alaska to the

other three Cook Inlet operators who

plan to drill after promulgation of this

rule. EPA investigated the possibility of

disposing of drilling wastes at an onland oil and gas waste disposal site

available to Cook Inlet operators located

in Idaho. EPA determined that, while it

is generally more economical to dispose

of drill wastes via grinding and

injection, in the case of smaller volumes

of drilling wastes, it would be more cost

effective to dispose of the wastes by

shipping them to the Idaho disposal

facility.

Land disposal of oil and gas wastes is

also available to Cook Inlet operators at

a disposal facility located in Oregon.

EPA performed its costing of land

disposal assuming the use of the Idaho

facility (see discussion of costs later in

this section). EPA expects that costs to

dispose of the wastes at the Oregon

facility would be close to or less than

costs using the Idaho facility because

transportation of wastes to the Oregon

facility would utilize barging to a greater

extent, making overall transportation

costs less.

The results of this investigation show

that the volume of drilling fluids and

drill cuttings wastes generated in Cook

Inlet can be either disposed of on-land

or by grinding and injection. However,

during the previous Offshore Guidelines

rulemaking affecting Alaska offshore

drilling operations, and early in the data

gathering stages of this proposed rule,

operators raised concerns that

compliance with zero discharge could

significantly interfere with drilling

operations. EPA does not have sufficient

information supporting these concerns,

and solicits comments on these issues.

Therefore, for this proposal, EPA is

also considering options which would

allow the discharge of the drilling fluids

and drill cuttings in Cook Inlet

providing they were to meet certain

limitations. These limitations would

prohibit the discharge of diesel oil and

free oil using the static sheen test, limit

cadmium and mercury in the stock

barite used in fluid compositions and

toxicity at either 30,000 ppm (SPP) or a

more stringent toxicity in range of

100,000 ppm (SPP) to 1 million ppm

(SPP). Drilling fluids and drill cuttings

not meeting these limitations would not

be allowed to be discharged, and

therefore, would have to be injected or

sent to shore for disposal. EPA would

base the more stringent toxicity

limitations (based on further evaluation

as discussed below), in part, on the

volume of drilling wastes it determines
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9443

could be injected or disposed of onshore

without interfering with ongoing

drilling operations.

Prior to, and during the offshore

rulemaking, EPA conducted bioassay

tests on eight generic mud types

(encompassing virtually all water-based

muds, exclusive of specialty additives,

primarily used on the outer continental

shelf), and, EPA established a toxicity

limitation of 30,000 ppm (SPP). Even in

offshore Alaska, drilling was not

evaluated for specific locations, thus

technical drilling requirements for

adequate drilling with a focus on small

localized areas were not considered in

setting the limitation for the offshore

rule. One alternative option for the

coastal rule would be to set the

limitations for Cook Inlet equal to the

offshore limitations for Alaska.

As discussed above, another option

would retain the offshore limitations but

require a more stringent toxicity

requirement. The toxicity limit would

be based on a relationship between the

achievable toxicity of the drilling wastes

and the volume of these wastes that

could be disposed of onshore or by

grinding and injection without

interfering with ongoing drilling

operations (e.g., some fraction of the

volume of wastes generated and covered

by the zero discharge option).

In order to determine the appropriate

toxicity level for the more stringent

toxicity option, EPA attempted to

evaluate effluent toxicity test results for

Cook Inlet drilling fluids and cuttings

discharges. EPA reviewed permit

compliance monitoring records, from

EPA’s Region 10, containing 161 sets of

results for toxicity testing of drilling

fluids and drill cuttings used in the

Alaska offshore and coastal regions

between 1985 and 1994. (The measure

of toxicity is a 96 hour test that

estimates the concentration of drilling

fluids suspended particulate phase

(SPP) that is lethal to 50 percent of the

test organisms.) The records were

summarized into a database which was

evaluated on the basis of the toxicity of

drilling fluids and drill cuttings used in

Alaska as a whole and Cook Inlet in

particular. After sorting the database to

eliminate inadequate data, such as

drilling fluids contaminated by pills and

incomplete toxicity tests, 104 sets of

results were retained for all of Alaska,

with 59 of these from Cook Inlet.

Of the Cook Inlet bioassay test results,

83 percent were less toxic than 100,000

ppm (SPP); 60 percent were less toxic

than 500,000 ppm; and one percent

exhibited no toxic effect (i.e., 1 million

ppm or greater with less than 50 percent

mortality of the test organism). (Note

that toxicity is inversely related to the

96-hour bioassay results so as the values

cited above increase, toxicity decreases).

These evaluations utilized an

available database obtained from EPA’s

Region 10, which provides an account

of the relationship between toxicity and

drilling fluids currently being

discharged. The toxicity values are

identified in the available database by

operator, permit number, well name,

date and base fluids system (mud). In

addition, some of the values are related

to an identified volume of muds

discharged. However, many of the

values in the summary do not have

either a volume identified or whether

the drilling fluids were discharged. This

available database is presently being

updated as EPA continues to identify

the volume of drilling wastes having

been discharged in Cook Inlet related to

specific toxicity test results. EPA solicits

any information useful in determining

an appropriate toxicity limitation that

individual Cook Inlet operators have

including data on the specific amounts

of drilling wastes generated versus

discharged and their corresponding

toxicity test results.

4. Options Considered

EPA has developed three options for

the control and treatment of drilling

fluids and drill cuttings. As mentioned

earlier in this preamble, dewatering

effluent may be a wastestream generated

separately. However, because it consists

of constituents that originate entirely

within the drilling fluids and cuttings

solids control system, EPA will not be

regulating dewatering effluent

separately. Rather, EPA proposes to

make the drilling fluids and cuttings

options applicable to the dewatering

effluent wherever this wastestream may

be generated.

The three options considered by EPA

contain zero discharge for all areas,

except two of the options contain

allowable discharges for Cook Inlet. One

of these options which would allow

discharges meeting a more stringent

toxicity limitation would require an

additional notice for public comment

since the specific toxicity limitation has

not been determined at this time (as

discussed in this section). The three

options are:

Option 1: Zero discharge for all areas

except Cook Inlet where discharge

limitations require toxicity of no less

than 30,000 ppm (SPP), no discharge

of free oil and diesel oil and no more

than 1 mg/1 mercury and 3 mg/1

cadmium in the stock barite.

Option 2: Zero discharge for all areas

except for Cook Inlet where discharge

limitations would be the same as

Option 1, except toxicity would be set

to meet a limitation between 100,000

ppm (SPP) and 1 million ppm (SPP).

Option 3: Zero Discharge for all areas.

As discussed later in this section, all

of the above options are being coproposed.

Option 1 would require zero

discharge of drilling fluids and cuttings

for all coastal drilling operations except

those located in Cook Inlet. Allowable

discharge limitations for drilling fluids

and cuttings in Cook Inlet would require

compliance with a toxicity value of no

less than 30,000 ppm (SPP); no

discharge of free oil (as determined by

the static sheen test); no discharge of

diesel oil and 1 mg/kg of mercury and

3 mg/kg of cadmium in the stock barite.

(These are the same limitations as those

for offshore drilling operations waste

discharges in the Alaska.)

Option 2 would require all operators

to meet the same zero discharge

limitation for the drilling fluids and

cuttings in all areas except for Cook

Inlet. In Cook Inlet, the drilling fluids

and cuttings discharges would be

required to meet the same limitations as

in Option 1 except that a more stringent

toxicity limitation would be imposed.

Instead of meeting a toxicity limitation

of 30,000 ppm (SPP), a toxicity

limitation between 100,000 ppm (SPP)

and 1 million ppm (SPP) would be met.

The toxicity limitation range of

between 100,000 ppm (SPP) and one

million ppm (SPP) reflects the range of

toxicity measurements resulting from

EPA’s evaluation of the current practice

for drilling in Cook Inlet. As discussed

previously in this section, an attempt

was made in this evaluation to

determine the volumes of drilling

wastes being discharged and their

respective toxicity levels. Because of the

lack of identified discharge volumes for

some of the toxicity test results, this

determination could not be completed.

Using the 83 percent of drilling wastes

which reflects the fraction of test results

less toxic than 100,000 ppm (SPP), and

coincidentally also reflects the fraction

of identified volumes less toxic than one

million ppm (SPP), costs and discharge

loadings were developed for this option.

(The method used to derive this range

is separate and distinct from the

statistical methodologies generally used

by EPA in effluent guidelines

regulations to derive 30-day average and

daily maximum limitations calculated

from the 95th and 99th percentiles,

respectively.) However, due to the above

discussed limitations with the data base,

EPA is currently only able to estimate

an achievable toxicity limit in the range

of 100,000 ppm (SPP) to one million

ppm (SPP). As described earlier under
9444 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

‘‘Additional Technologies Considered’’

of this section, EPA is continuing to

evaluate toxicity test results and

volumes and any other data for drilling

fluids used and discharged in Cook Inlet

in an effort to derive a more specific

limitation and resulting revisions of

costs and loadings. A supplemental

notice presenting the data and revised

results and soliciting comment would

be necessary prior to promulgation.

Option 3 would prohibit the discharge

of drilling fluids and cuttings from all

coastal oil and gas drilling operations.

This option utilizes grinding and

injection and onshore disposal as a basis

for complying with zero discharge of

drilling fluids and cuttings.

The technology Options 1 and 2 for

Cook Inlet have been developed taking

into consideration the possibility that

Cook Inlet operations are unique to the

industry due to a combination of

climate, transportation logistics, and

structural and space limitations that

interfere with the drilling operations.

These options are based on a degree of

recycling and reuse, onshore disposal

and/or grinding and injection of a

portion of the wastes if they cannot

meet the limitations, in addition to

product substitution in order to attain

the limitations and be able to discharge

a portion of the generated wastes.

EPA solicits comments on the two

discharge options containing specific

data on the toxicity levels achievable for

drilling fluids compositions and drill

cuttings and why the more toxic of the

compositions must be used in order to

successfully drill. Also, information is

solicited on the degree to which zero

discharge all would interfere with

drilling operations in Cook Inlet, given

the estimate of a limited amount of

drilling planned.

5. BCT Options Selection

a. BCT Cost Test Methodology.

The methodology for determining

‘‘cost reasonableness’’ was proposed by

EPA on October 29, 1982 (47 FR 49176)

and became effective on August 22,

1986 (51 FR 24974). These rules set

forth a procedure which includes two

tests to determine the reasonableness of

costs incurred to comply with candidate

BCT technology options. If all candidate

options fail either of the tests, or if no

candidate technologies more stringent

than BPT are identified, then BCT

effluent limitations guidelines must be

set at a level equal to BPT effluent

limitations. The cost reasonableness

methodology compares the cost of

conventional pollutant removal under

the BCT options considered with the

cost of conventional pollutant removal

at publicly owned treatment works

(POTWs).

BCT limitations for conventional

pollutants that are more stringent than

BPT limitations are appropriate in

instances where the cost of such

limitations meet the following criteria:

• The POTW Test: The POTW test

compares the cost per pound of

conventional pollutants removed by

industrial dischargers in upgrading from

BPT to BCT candidate technologies with

the cost per pound of removing

conventional pollutants in upgrading

POTWs from secondary treatment to

advanced secondary treatment. The

upgrade cost to industry must be less

than the POTW benchmark of $0.53 per

pound ($0.25 per pound in 1976 dollars

indexed to 1992 dollars).

• The Industry Cost-Effectiveness

Test: This test computes the ratio of two

incremental costs. The ratio is also

referred to as the industry cost test. The

numerator is the cost per pound of

conventional pollutants removed in

upgrading from BPT to the BCT

candidate technology; the denominator

is the cost per pound of conventional

pollutants removed by BPT relative to

no treatment (i.e., this value compares

raw wasteload to pollutant load after

application of BPT). The industry cost

test is a measure of the candidate

technology’s cost-effectiveness. This

ratio is compared to an industry cost

benchmark, which is based on POTW

cost and pollutant removal data. The

benchmark is a ratio of two incremental

costs: the cost per pound to upgrade a

POTW from secondary treatment to

advanced secondary treatment divided

by the cost per pound to initially

achieve secondary treatment from raw

wasteload. The result of the industry

cost test is compared to the industry

Tier I benchmark of 1.29. If the industry

cost test result for a considered BCT

technology is less than the benchmark,

the candidate technology passes the

industry cost-effectiveness test. In

calculating the industry cost test, any

BCT cost per pound less than $0.01 is

considered to be the equivalent of de

minimis or zero costs. In such an

instance, the numerator of the industry

cost test and therefore the entire ratio

are taken to be zero and the result

passes the industry cost test.

These two criteria represent the twopart BCT cost reasonableness test. Each

of the regulatory options was analyzed

according to this cost test to determine

if BCT limitations are appropriate.

b. BCT Cost Calculations and Options

Selection.

(i) Other than Cook Inlet.

In addition to considering setting the

BCT limitations equal to BPT, EPA

considered two additional BCT options

for control of conventional pollutants in

drilling fluids and drill cuttings. Both of

these options would require zero

discharge of drilling fluids and drill

cuttings throughout the subcategory

except in Cook Inlet. Because all

operators throughout the entire

subcategory, except in Cook Inlet, are

currently meeting a zero discharge

requirement, or in the case of

dewatering effluent, are practicing zero

discharge already, there is zero cost and

zero removal of conventional pollutants

for this limitation. Thus, EPA has

determined that zero discharge passes

the BCT cost tests and other statutory

factors and proposes a BCT limitation

equal to zero discharge for all areas

except Cook Inlet.

(ii) Cook Inlet.

In Cook Inlet, EPA considered either

zero discharge (Option 3, above), or

allowing discharge based on

requirements identified in Option 2,

above. EPA did not consider Option 1

for Cook Inlet, allowing discharge at the

current Offshore Guidelines limitations

with a toxicity limit of 30,000 ppm

(SPP), as a distinct BCT option because

the amount of removal of the

conventional pollutant oil and grease, as

oil, from discharge by this level of

toxicity could not be determined from

that removed by the current BPT

requirement of no free oil.

The POTW test (first part of the two

part cost-reasonableness test) is

calculated by comparing the cost per

pound of conventional pollutant

removed in upgrading from BPT to the

BCT candidate options. EPA determined

the costs of each BCT option for drilling

fluids, drill cuttings, and drilling fluids

and drill cuttings combined.

EPA included only oil and grease and

TSS in the BCT analysis. EPA did not

include BOD because it is not a

parameter normally measured in

wastewaters from this industry since it

is associated with the oil content, e.g.,

oil and grease measurement. The use of

BOD and oil and grease would result in

double-counting, thus giving erroneous

results. EPA did not include the

parameter of settleable solids in the BCT

analysis because settleable solids are not

a conventional pollutant.

EPA calculated cost of the BPT

limitations for drilling fluids and drill

cuttings for Cook Inlet using the model

well characteristics and disposal costs

used for the offshore wells (in the

development of the Offshore

Guidelines). The volume of wastes

(drilling fluids and cuttings) was based

on the 1993 Coastal Oil and Gas

Questionnaire data for Cook Inlet. EPA

based the costs associated with meeting
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9445

the BPT requirement of ‘‘no free oil’’ on

land-based disposal of oil-based drilling

fluids and oil laden cuttings and

substitution of mineral oil for diesel oil

in pills. As was done in the Offshore

Guidelines BCT determinations, oil

content, which is normally measured in

drilling wastes, was used as surrogate

for the oil and grease conventional

pollutant in the calculation of pollutant

removals. The following are annual BPT

costs and conventional pollutant

removals per well for drilling fluids and

cuttings:

Annual Cost (1992 Dollars):

Drilling Fluids—$40,275

Drill Cuttings—$22,355

TSS Removals (Annual):

Drilling Fluids—267,911 pounds

Drill Cuttings—297,880 pounds

Oil and Grease Removals (Annual):

Drilling Fluids—207,584 pounds

Drill Cuttings—92,895 pounds

The three options for Cook Inlet were

evaluated according to the BCT cost

reasonableness tests. The pollutant

parameters used in this analysis were

total suspended solids and oil and

grease. All options, except the ‘‘BPT’’

option, no discharge of free oil, fail the

BCT cost reasonableness test. Costs for

the ‘‘BPT’’ option are equal to zero

because it reflects current practice. The

results of the POTW test (first part of the

BCT cost test) for the zero discharge

option (Option 3) is $0.151 per pound

of conventional pollutant removed. A

value of less than $0.534 per pound

(1992$) is required to pass the POTW

test. Thus, this option passes the POTW

test. The results of the Industry Cost

Ratio Test (ICR) is 2.097. As this value

of 2.097 is greater than 1.29, zero

discharge for drilling fluids and drill

cuttings in Cook Inlet fails the second

test. Thus, EPA proposes that BCT be

equal to BPT for drilling fluids and drill

cuttings discharges in Cook Inlet.

EPA conducted the same set of tests

for Option 3 for the separate

wastestreams of drilling fluids and

cuttings. The results of the BCT cost

tests for Option 2 and 3 are contained

in Table 3 of the preamble, show that

drilling fluids fail the second test, and

cuttings pass. (Results for Option 1 are

equal to zero and are not shown on

Table 3).

The same set of tests are conducted

for the Option 2, prohibitions on the

discharge of free oil and diesel oil,

limitations on cadmium and mercury in

stock barite and toxicity limitation of

between 100,000 and 1 million ppm

(SPP) or greater. For the purpose of

conducting these calculations, a volume

fraction of 0.83 (83 percent) of the

drilling fluids and cuttings was

anticipated to comply with a toxicity

limitation of between 100,000 ppm

(SPP) and 1 million ppm (SPP). A

summary of the results of these tests,

also presented in Table 4, demonstrate

drilling fluids and cuttings both fail the

cost test. Thus, both candidate BCT

options fail the ICR test, and BCT is set

equal to Option 1 for this proposal

which is equal to zero discharge

everywhere except for Cook Inlet where

BPT would apply.

The specific calculation of these BCT

cost reasonableness tests for the drilling

fluids and drill cutting options for Cook

Inlet are discussed further in the Coastal

Technical Development Document.

TABLE 4.—BCT Cost Test Results for Drilling Fluids and Drill Cuttings for Cook Inlet 1

Regulatory option

Pollutant removal (lb/

well)

Compliance

cost 1 ($/

well)

BCT cost

($/lb)

Pass POTW

(<0.534) 2

BPT cost

($/lb) ICR ratio Pass ICR (<1.29)

Drilling Fluids

Option 2 ..................... 191,693 129,026 0.673 No ............................. 0.085 ...................

Option 3 ..................... 1,127,603 418,888 0.371 Yes ............................ 0.085 4.365 No.

Drill Cuttings

Option 2 ..................... 389,756 30,226 0.078 Yes ............................ 0.057 1.368 No.

Option 3 ..................... 2,292,681 98,258 0.043 Yes ............................ 0.057 0.754 Yes.

Drilling Fluids and Cuttings

Option 2 ..................... 581,449 159,252 0.274 Yes ............................ 0.072 3.806 No.

Option 3 ..................... 3,420,284 517,146 0.151 Yes ............................ 0.072 2.097 No.

1 Results of Option are equal to zero and are not shown in this table.

2 Compliance Cost and Conventional Pollutants Removal are incremental to BPT.

3 1986 benchmark (0.46) adjusted to 1992 dollars $0.534.

6. BAT and NSPS Options

EPA is co-proposing all three options

considered for the BAT and NSPS level

of control for drilling fluids and drill

cuttings. A discussion of the costs and

impacts and description of the selection

rationale is contained below.

a. Costs.

No costs would be incurred by the

industry to comply with Option 1

because the requirements are reflective

of current practice. Costs incurred by

the coastal industry to comply with

Option 2 would amount to

approximately $1.4 million annually.

These costs are attributed only to the

Cook Inlet operators who would be

required to meet the Offshore

limitations and a more stringent toxicity

limitation based on an estimate that 83

percent of the drilling fluids and drill

cuttings would pass a toxicity limitation

of between 100,000 ppm (SPP) and

1,000,000 ppm (SPP). Thus, 17 percent

of the drilling wastes would need to be

disposed of either onshore or by

grinding and injection.

Costs to comply with Option 3 (zero

discharge all) are attributed only to

Cook Inlet operators not currently

meeting a zero discharge requirement

for drilling fluids and drill cuttings (all

other coastal operators including the

North Slope of Alaska are already

practicing zero discharge). Costs to

comply with this option are estimated to

be approximately $3.9 million annually

for Cook Inlet operators. EPA conducted

an extensive analysis of possible waste

disposal options available to Cook Inlet

operators in order to estimate the costs

to comply with a zero discharge

requirement. The basis for this cost

analysis is that approximately 76

percent of the drilling fluids and
9446 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

cuttings generated in Cook Inlet would

be hauled to shore for disposal onshore,

and the other 24 percent would be

injected following grinding, into

dedicated disposal wells regulated by

the Underground Injection Control (UIC)

program.

Of the five Cook Inlet operators, two

operators generate about 76 percent of

the drilling fluids and drill cuttings in

Cook Inlet and, have access to a landfill

in Alaska. One operator has no future

plans to drill. The remaining two

operators, who generate about 24

percent of the drilling wastes, would be

expected to, for costing purposes, grind

and inject to comply with the zero

discharge requirement. Out of the five

Cook Inlet operators, information

obtained by EPA in 1993 indicated that

one of them had no plans to drill in the

Inlet. Recent (1995) information from an

additional Cook Inlet operator relates

that this operator also no longer has

plans to drill in the Inlet. EPA

conservatively estimated that this

operator would have drilled six new

wells (out of a total of 36 for all of the

Cook Inlet operators) in the next seven

years. Due to the fact that this is very

recent information, the cost and

economic analyses presented in this

preamble have not deleted these six

drillings. Thus, the analysis was

performed assuming only one operator,

instead of two, operators will not be

drilling. However, retaining these six

drillings in the analyses will not only

provide a conservative estimate of the

costs and economic impacts, but may

serve to cover future changes in oil and

gas activity should decisions be made to

resume drilling.

Costs for land disposal include water

vessel transportation, storage prior to

transport to the disposal facility, truck

transportation to the disposal facility,

and landfill disposal costs. Costs for

grinding and injection include purchase

or rental of the grinding, slurrying and

pumping equipment, and costs to drill

dedicated injection wells at the drill

site.

To determine the volume of drilling

wastes requiring disposal, EPA obtained

the projected drilling schedules for the

Cook Inlet operators using information

from the 1993 Coastal Oil and Gas

Questionnaire and contacts with

industry. EPA’s projections estimate

that 36 new wells and 19 recompletions

will be drilled in the seven years

following scheduled promulgation of

this rule. (Recompletions are drilling

operations which utilize an existing

well but drill to a deeper formation than

that which the well was previously

producing from). Using information

about the volume of drilling fluids and

drill cuttings generated per well, and

the projected amount of drilling over the

seven years following scheduled

promulgation, EPA estimates that the

total amount of drilling fluids and

cuttings annually discharged from these

drilling operations will be

approximately 79,000 barrels.

EPA also considered the logistical

difficulties of transporting drilling

wastes in the Cook Inlet as part of in

EPA’s costing analysis of the options. To

achieve zero discharge, certain

platforms would transport drill wastes

to the eastern side of Cook Inlet by

supply boat during ice conditions, and

store the wastes at a transfer station

until they could be transported by barge

to an existing landfill facility on the

west side of the Inlet. During the

summer months, transport of wastes

would be accomplished by barge

directly to the west side.

Costs for the two operators to dispose

of their wastes in the Alaskan landfill

average $39/barrel. Costs for the other

two operators (one operator has no

future plans to drill) to dispose of their

wastes by grinding and injection average

$53/bbl. A weighted average for

disposal of 76 percent of the drilling

wastes by Alaskan landfills and 24

percent by grinding and injection

equates to $42/bbl. On a per well basis,

this amounts to approximately $425,000

and $600,000 for each recompletion and

new well drilled, respectively.

The costs to comply with Option 2 are

approximately $1.4 million annually.

Capital expenditures are close to those

incurred to meet Option 3 due to the

fact that most operators will be required

to install the same equipment regardless

of the amount of wastes requiring

disposal. The economic impact analysis

associated with this option would result

in a 1.3 percent reduction in the

estimated lifetime production for the

existing platforms in Cook Inlet as a

result of three wells not being drilled.

The net present value of this production

loss (reduction in producers’ net

income) is $263,000 or less than 0.1

percent of baseline net present value.

The average well life decreases by 0.2

years as a result of this option.

The results of the economic impact

analysis associated with the costs for the

zero discharge all option (Option 3) for

drilling fluids and cuttings show a 2.7

percent reduction in the estimated

lifetime production for the existing

platforms in Cook Inlet (an additional

2.6 percent over Option 2). The

associated net present value loss of

production is approximately $6.1

million. This is reflective of the estimate

that Cook Inlet platforms may close on

average, 11 months earlier than their

projected average lifetime of 11 years

without this requirement. There are no

well or platform shutdowns or barriers

to new drilling activities as a result of

these costs. However, three new wells

would not be drilled. The results of the

economic impact analysis are discussed

in Section VII of the preamble. For new

sources, EPA expects that the costs of

complying with NSPS would be equal to

or less than those for existing sources.

An analysis of non-water quality

environmental impacts for BAT and

NSPS was performed. The estimated

impacts for the options are discussed in

Section VIII of the preamble. The

increased energy use and air emissions

and availability of land disposal sites

and capacity are identified.

b. Rationale for Option Selection.

EPA has not selected a preferred

option for control of drilling fluids and

drill cuttings under BAT and NSPS but,

rather is co-proposing all three options.

EPA has determined, based on available

information, that all three options are

technologically and economically

achievable and have acceptable nonwater quality impacts. However, due to

possible operational interferences (for

Option 3), the lack of sufficient data to

set a toxicity limitation more stringent

than 30,000 ppm (SPP) (for Option 2)

and the high cost-effectiveness results

for both Options 2 and 3, a preferred

option has not been selected. EPA

solicits comments on the

appropriateness of each option.

A large majority of operators are

already discharging at levels less toxic

than the toxicity limitations of 30,000

ppm (SPP) contained in Option 1. Thus,

this is a no cost option incurring no

economic or non-water quality

environmental impacts.

Option 2 requires zero discharge for

all operators except in Cook Inlet where

operators would be required to meet the

Offshore subcategory limitations in

addition to a toxicity limitation of

between 100,000 ppm (SPP) and

1,000,000 ppm (SPP). This option

would cost $1.4 million annually and

results in less than a 0.1 percent

reduction in estimated lifetime

production for Cook Inlet platforms

which would not significantly reduce

the profit potential for these operators.

Option 2 would result in the removal of

approximately 3.9 million pounds of

pollutants being discharged per year (or

1264 pounds in toxic equivalents),

assuming a volume of 17 percent of the

discharges would not meet a toxicity

limit of between 100,000 ppm and one

million ppm (SPP) and would therefore

be disposed of by grinding and injection

or on land. Out of the 3.9 million

pounds removed annually less than 0.02
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9447

percent consists of toxic priority

pollutants (or 642 pounds).

Due to limitations with the data base,

EPA is currently only able to estimate

an achievable toxicity limit in the range

of 100,000 ppm (SPP) to one million

ppm (SPP). As described earlier under

‘‘Additional Technologies Considered’’

of this section, EPA is continuing to

evaluate toxicity test results and

volumes and other data for drilling

fluids used and discharged in Cook Inlet

in an effort to derive a more specific

limitation. A supplemental notice

presenting the data and soliciting

comment would be necessary prior to

promulgation.

Option 3 would cost the industry $3.9

million annually and result in the

reduction of 23 million pounds of

pollutants being discharged per year (or

7375 in toxic pounds equivalents). Zero

discharge of drilling fluids and drill

cuttings is widely practiced in other

coastal areas other than Cook Inlet,

including the Gulf of Mexico, California,

and the North Slope of Alaska. In Cook

Inlet, zero discharge is not currently

practiced but for a small amount of

drilling fluids (approximately one

percent) that do not meet permit limits.

Zero discharge is technologically

available because operators are able to

comply with zero discharge by either

disposing of their drilling fluids and

drill cuttings onshore or by grinding and

injecting the waste. The costs of this

option would result in a 2.7 percent

reduction in the estimated lifetime

production for Cook Inlet platforms,

which would not significantly reduce

the profit potential for these operators.

Thus, EPA believes these costs are

economically achievable. However,

concerns have been raised that zero

discharge would interfere with drilling

operations, in part because the weather

conditions and tidal fluctuations in the

Inlet pose logistical difficulties for

drilling waste transportation especially

during winter months. In addition,

while Option 3 would result in the

removal of 23 million pounds of

pollutants per year, less than 0.02

percent of which are toxic pollutants,

the $3.9 million annually incurred by

industry to remove the 3760 pounds of

priority toxic pollutants indicates that

this option is not cost effective. (See

EPA’s cost effectiveness report entitled

Cost Effectiveness Analysis of Effluent

Limitations Guidelines and Standards

for the Coastal Oil and Gas Industry in

the rulemaking record for this proposal

and additional discussion in Section VII

of this preamble.) In Cook Inlet,

operators are not currently practicing

zero discharge. EPA estimates that to

comply with a total zero discharge

requirement, 24 percent of the drilling

fluids and drill cuttings would be

ground and injected into dedicated

wells, and 76 percent would be

disposed of onshore.

EPA is soliciting comments on

whether the drilling fluids and cuttings

volumes removed by these options are

deminimus, and on the effect that

weather and transportation logistics,

cost effectiveness, and other factors

(e.g., types of fluids used and their

composition, toxicity values, etc.) may

have on the applicability, achievability

and practicality of both Options 2 and

3.

EPA does not expect any new source

development wells drilled in Cook Inlet

in the seven years following the

scheduled promulgation of this rule.

This is because all development wells

are expected to be drilled from existing

platforms in Cook Inlet. According to

the definition of new sources, these

wells would be existing sources.

Additionally, any drillings that may

occur in the recently discovered Sunfish

formation in Upper Cook Inlet, are

projected to be exploratory wells, which

are also existing sources according to

the new source definition. Thus, no

costs will be attributed to NSPS in Cook

Inlet because no new sources are

projected for this area. However, in the

case that a new source would be drilled

in Cook Inlet, EPA has determined that

zero discharge would not pose a

significant barrier to entry for the

drilling project. The same options are

being considered for NSPS as for BAT,

and again, no one preferred NSPS

option is being selected in this proposal.

Costs may be less than BAT because

process modifications can be

incorporated into the drilling rig design

prior to its installation rather than

retrofitting an existing operation.

Whenever EPA determines that BAT is

economically achievable, equivalent

NSPS requirements would also be

economically achievable, and cause no

significant barrier to entry. EPA solicits

comments on whether NSPS should be

more stringent than BAT for Cook Inlet

drilling fluids and cuttings.

EPA also finds the non-water quality

environmental impacts of Option 2 and

zero discharge (Option 3) to be

acceptable. Again, non-water quality

environmental impacts attributable to

this rule would occur only in Cook

Inlet. The air emissions and energy

requirements associated with waste

transportation were calculated for the

two operators expected to utilize

onshore landfill disposal to

accommodate the wastes from their

drilling operations. For the remaining

two operators who will be drilling and

do not have access to onshore disposal,

EPA has calculated the air emissions

and energy requirements resulting from

grinding and injection to meet zero

discharge. EPA has found that these

non-water quality environmental

impacts represent only a very small

fraction of the total air emissions and

energy requirements from normal

operations, and that these non-water

quality environmental impacts are

acceptable. As stated above, EPA does

not expect any new sources to be

initiated in Cook Inlet. EPA, however,

believes that the non-water quality

environmental impacts resulting from

any such activity would be equal to or

less than those anticipated for existing

sources, which EPA has found

acceptable.

8. PSES and PSNS

Section 307 of the CWA authorizes

EPA to develop pretreatment standards

for existing sources (PSES) and new

sources (PSNS). Pretreatment standards

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

pretreatment standards for existing

sources are to be technology based and

analogous to the best available

technology economically achievable

(BAT) for direct dischargers. The

pretreatment standards for new sources

are to be technology-based and

analogous to the best available

demonstrated control technology used

to determine NSPS for direct

dischargers. New indirect discharging

facilities, like new direct discharging

facilities, have the opportunity to

incorporate the best available

demonstrated technologies, including

process changes, and in-plant controls,

and end-of-pipe treatment technologies.

EPA determines which pollutants to

regulate in PSES and PSNS on the basis

of whether or not they pass through,

interfere with, or are incompatible with

the operation of POTWs.

Based on the 1993 Coastal Oil and Gas

Questionnaire and other information

reviewed as part of this rulemaking,

EPA has not identified any existing

coastal oil and gas facilities which

discharge drilling fluids and cuttings to

publicly owned treatment works

(POTW’s), nor are any new facilities

projected to direct these wastes in such

manner. However, due to the high solids

content of drilling fluids and cuttings,

EPA is proposing to establish

pretreatment standards for existing and

new sources equal to zero discharge

because these wastes are incompatible

with POTW operations. For further
9448 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

discussion, see the Coastal Technical

Development Document. For PSNS, zero

discharge would not cause a barrier to

entry for the same reasons as discussed

previously under Part 6.b. of this

Section.

B. Produced Water

1. Waste Characterization

Produced water is brought to the

surface during the oil and gas extraction

process and includes: formation water

extracted along with oil and gas;

injection water used for secondary oil

recovery that has broken through the

formation and mixed with the extracted

hydrocarbons; and various well

treatment chemicals added during the

production and oil/water separation

processes. Produced water is the highest

volume waste in the coastal oil and gas

industry. Depending on the age of a well

and site-specific formation

characteristics, the produced water can

constitute between 2 percent and 98

percent of the gross fluid production at

a particular well. Generally, in the early

production phase of a well the produced

water volume is relatively small and the

hydrocarbon production makes up the

bulk of the fluid. Over time, the

formation approaches hydrocarbon

depletion and the produced water

volume usually exceeds the

hydrocarbon production. Based on

information received in the 1993 Coastal

Oil and Gas Questionnaire, the average

produced water rate from a well is

approximately 1180 barrels per day

(bpd) in Cook Inlet and 270 bpd in the

Gulf coast. EPA estimates that 228

million barrels per year (bpy) of

produced water is discharged to surface

waters by the coastal oil and gas

industry.

As part of this rulemaking, EPA has

embarked upon a systematic effluent

sampling program to identify and

quantify the pollutants present in

produced water, with an emphasis

toward the identification of listed

priority pollutants. Details of EPA’s data

collection activities are presented in

Section V of this notice, with additional

detail and sampling results discussed in

the Coastal Technical Development

Document. The information collected

has confirmed the presence of a number

of organic and metal priority pollutants

in produced water.

Pollutants contained in coastal oil and

gas industry produced water discharges

from facilities with treatment systems

used to meet the BPT level permit limits

were identified as part of EPA’s

sampling effort. A summary of the data

from these sampling activities is

contained in the Coastal Technical

Development Document. EPA’s

sampling data and the industrysupplied Cook Inlet Study identified

many organic priority pollutants and all

of the 13 metal priority pollutants as

being present in BPT treated produced

water discharges following some

treatment for oil and grease (oil)

removal. The priority organics most

often present in significant amounts

were benzene, naphthalene, phenol,

toluene, 2-propanone, ethylbenzene and

xylene. In addition to the priority

pollutants, EPA identified total

suspended solids, oil and grease, and a

number of nonconventional pollutants

including barium, chlorides, ammonia,

magnesium, strontium and iron present

in produced water.

2. Selection of Pollutant Parameters

a. Pollutants Regulated.

Where zero discharge would be

required, all pollutants found in

produced water discharges would be

controlled. Where discharges would be

allowed, i.e. Cook Inlet, EPA would be

regulating oil and grease under BAT as

an indicator pollutant controlling the

discharge of toxic and nonconventional

pollutants. Oil and grease would be

limited under BCT as a conventional

pollutant and under NSPS as both a

conventional pollutant and as an

indicator pollutant controlling the

discharge of toxic and nonconventional

pollutants.

It has been shown previously in the

development of the Offshore Guidelines

(See the Offshore Technical

Development Document, Section VI)

that oil and grease serves as an indicator

for toxic pollutants in the produced

water wastestream, including phenol,

naphthalene, ethylbenzene, and toluene.

During its development of the Offshore

Guidelines, EPA showed that gas

flotation technology (the technology

basis for the oil and grease limitations)

removes both metals and organic

compounds, resulting in lower

concentration levels in the discharge for

the above priority pollutants (See

Section IX of the Offshore Technical

Development Document).

b. Pollutants Not Regulated.

The feasibility of regulating separately

each of the constituents of produced

water determined to be present was also

evaluated during the development of the

Offshore Guidelines (See Section VI of

the Offshore Technical Development

Document). EPA determined that it is

not feasible to regulate each pollutant

individually for reasons that include the

following: (1) The variable nature of the

number of constituents in the produced

water, (2) the impracticality of

measuring a large number of analytes,

many of them at or just above trace

levels, (3) use of technologies for

removal of oil which are effective in

removing many of the specific

pollutants, and (4) many of the organic

pollutants are directly associated with

oil and grease because they are

constituents of oil, and thus, are directly

controlled by the oil and grease

limitation. These reasons also apply to

the Coastal Guidelines.

While the oil and grease limitations

limit the discharge of toxic pollutants,

EPA determined, during the Offshore

Guidelines rulemaking, that certain of

the toxic priority pollutants, such as

pentachlorophenol, 1,1,-dichloroethane,

and bis(2-chloroethyl) ether would not

be controlled by the limitations on oil

and grease in produced water. EPA is

not proposing to regulate these

pollutants in this rule because EPA did

not detect them in the samples within

the coastal oil and gas data base. (See

the Coastal Technical Development

Document).

3. Control and Treatment Technologies

a. Current Practice.

Based on information collected by the

1993 Coastal Oil and Gas Questionnaire

as well as industry contacts, no coastal

oil and gas facilities are discharging

produced water in Alabama, Florida,

California or Alaska’s North Slope. This

is due to a combination of factors

including operational preference,

waterflooding, and/or state

requirements. In addition, the Louisiana

Department of Environmental Quality

issued regulations in 1992 (LAC:33,IX,

7.708) which prohibit discharges of

produced water to fresh water areas

characterized as ‘‘upland’’ after July 1,

1992. The regulation defines ‘‘upland’’

as ‘‘any land not normally inundated

with water and that would not, under

normal circumstances, be characterized

as swamp of fresh, intermediate,

brackish or saline marsh’’. The

regulation does, however, allow

discharges to the major deltaic passes of

the Mississippi River and the

Atchafalaya River. The same regulation

also requires that discharges inland of

the inner boundary of the Territorial

Seas into intermediate, brackish or

saline waters must either cease

discharges or comply with a specific set

of effluent limitations. These

requirements must be met within a

certain time frame, as required in the

regulations, but, in most cases, no later

than January 1997.

In addition, EPA proposed general

NPDES permits (57 FR 60926, December

22, 1992) for production wastes which

would impose a prohibition on

discharges of produced water in coastal
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9449

areas of Texas and Louisiana. These

permits were finalized January 9, 1995

(60 FR 2387). The permits would not,

however, apply to facilities treating

offshore waters and discharging into the

main passes of the Mississippi and

Atachafalaya River. Based on these

permits requiring zero discharge, only

Alaska’s Cook Inlet and two sites in the

Gulf of Mexico would be discharging

produced water in the Coastal

subcategory at the time this final rule is

scheduled to be signed, currently July

1996.

The current BPT regulations

established for the coastal subcategory

limit the oil and grease content in the

discharged produced water. Existing

technologies for the removal of oil and

grease include gravity separation, gas

flotation, heat and/or chemical addition

to assist oil-water separation, and

filtration. Methods for the discharge or

disposal of produced water from

facilities in the coastal subcategory

include free fall discharge to surface

waters, discharge below the water

surface, use of channels to convey the

discharge to water bodies, and injection

via regulated Class II Underground

Injection Control (UIC) wells into

underground formations. As an

alternative, a number of production sites

transport produced water by pipeline,

truck or barge to shore facilities for

disposal in UIC Class II wells. At times,

this transport consists of the gross fluid

produced and the oil-water separation

takes place at the off-site facility.

While sampling data has indicated

quantifiable reductions of naphthalene,

lead, and ethylbenzene by BPT

treatment (i.e., by oil-water separation

technology), this data also demonstrates

the presence of significant levels of

priority pollutants remaining in the

treated effluent.

b. Additional Technologies.

In developing the proposed

regulation, EPA evaluated several

treatment technologies for application to

the produced water wastestream. These

technologies were considered for

implementation at the coastal

production sites and at the shore

facilities where much of the produced

water is currently treated for subsequent

discharge to coastal subcategory waters.

(1) Improved Gas Flotation.

Gas flotation is a treatment process

that separates low-density solids and/or

liquid particles (e.g., oil and grease)

from liquid (e.g., water) by introducing

small gas (usually air) bubbles into

wastewater. As minute gas bubbles are

released into the wastewater, suspended

solids or liquid particles are captured by

these bubbles, causing them to rise to

the surface where they are skimmed off.

EPA considered as an option using

gas flotation technology with chemical

addition as a basis for improving BPTlevel performance. This option would

require all coastal discharges of

produced water to comply with oil and

grease limitations of 29 mg/l monthly

average and a daily maximum of 42 mg/

l. The technology basis for these

limitations is improved operating

performance of gas flotation technology.

EPA has determined that gas flotation

systems could be improved to increase

removal efficiencies—i.e., the amount of

pollutants removed. Specific

mechanisms include proper sizing of

the gas flotation unit to improve

hydraulic loading (water flow rate

through the equipment), adjustment and

closer monitoring of engineering

parameters such as recycle rate and

shear forces that can affect oil droplet

size (the smaller the oil droplet, the

more difficult the removal), additional

maintenance of process equipment, and

the addition of chemicals to the gas

flotation unit. (See Offshore Technical

Development Document Section IX).

The addition of chemicals can be a

particularly effective means of

increasing the amount of pollutants

removed. Because the performance of

gas flotation is highly dependent on

‘‘bubble-particle interaction,’’ chemicals

that enhance that interaction will

increase pollutant removal.

Gas flotation is a technology which

has been used for many years in treating

produced water in the offshore

subcategory. In developing final effluent

limitations guidelines and standards for

the offshore subcategory (58 FR 12454;

March 4, 1993), EPA evaluated

comments and data submitted by the

industry which strongly urged EPA to

select improved gas flotation technology

as the basis for BAT limits and NSPS,

based on an Offshore Operator

Committee’s (OOC’s) 83 Platform

Composite Study. Industry further noted

that chemical additives would improve

the amount of oil and grease in

produced water that could be removed.

EPA thoroughly reviewed these

comments and additional data, and

agreed with industry that improved gas

flotation should be used as the

technology for setting BAT limits and

NSPS in the offshore subcategory.

In establishing BAT limits and NSPS

for produced water, EPA evaluated the

effluent data from the platforms in the

83 Platform Composite Study identified

as using improved gas flotation (e.g., use

of gravity separators and chemical

additives). First, EPA modeled the

offshore platform with ‘‘median’’ oil and

grease effluent values (i.e., 50 percent of

the platforms in the database had oil

and grease effluent values above (and 50

percent below) the median of the

effluent values measured at the median

platform. Based on the oil and grease

measured at the median platform after

improved gas flotation treatment, and

allowing for average ‘‘within-platform’’

variability, EPA set a daily maximum

limit on oil and grease at 42 mg/l, and

a 30-day average of 29 mg/l as the BAT

limits and NSPS. (See 58 FR 12462,

March 4, 1993).

In setting BAT limits and NSPS for

the offshore rule, EPA had a choice

among several different means of

measuring what is termed ‘‘oil and

grease’’ in produced water, two of

which are known as Method 413.1 and

Method 503E.

Under Method 413.1, freon is mixed

with a sample of produced water. The

container is then left at rest to separate

the water phase from the freon phase,

which includes those contaminants in

produced water that dissolve in freon.

The freon layer is then drained from the

container and distilled by heating,

leaving a residue. The residue is then

weighed and reported as the weight of

the ‘‘oil and grease’’ in that sample of

produced water. The results are

typically reported in milligrams of oil

and grease per liter of produced water.

Under Method 503E the same steps

are followed, with one exception. After

the freon layer is drained from the

container, but prior to distillation, silica

gel is added to the freon, and weighed.

Because the silica gel has the ability to

adsorb polar materials (e.g., some of the

hydrocarbons and fatty acids present)

that otherwise would have been

measured as oil and grease in the freon

residue by Method 413.1, the analytical

result reported under Method 503E is

less than that reported under Method

413.1. Because Method 413.1 measures

more of the oil and grease in produced

water, it gives a more complete picture

of the efficiency of the treatment system.

Because EPA had influent and effluent

data showing that oil and grease,

measured under Method 413.1, were

removed by the use of improved gas

flotation (Oil Content in Produced Brine

on Ten Louisiana Production Platforms,

September 1981) R.I.G. (No. 194), EPA

used improved gas flotation as the

technology basis for the rule and

established the limitations as measured

by Method 413.1 (See also Final Report,

Analysis of Oil and Grease Data

Associated with Treatment of Produced

Water by Gas Flotation Technology,

January 13, 1993, and 58 FR 12462,

March 4, 1993).

(2) Filtration.

The primary purpose of filtration is to

remove suspended matter, including
9450 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

insoluble oils, from produced water.

Additional removal of soluble

pollutants can also be achieved, but it

is not as significant as the reduction of

conventional pollutants such as total

suspended solids and oil and grease.

EPA has considered several types of

filtration systems as part of this

rulemaking, including granular,

membrane and cartridge filtration

technologies. EPA’s assessment of

granular filtration is based in part on

data collected from a coastal oil and gas

facility as part of the offshore

subcategory rulemaking (Three Facility

Study). Although economically

achievable, granular filtration was

rejected as the technology basis for

controlling discharges in this proposed

rule. EPA’s evaluation of granular

filtration performance data indicates

that while this technology does provide

some removals of priority and

nonconventional pollutants, the

pollutant removal efficiency of granular

filtration (in the range of 46–68 percent

oil and grease removal) is generally not

as effective as that attainable through

improved operation of gas flotation

technology (general oil and grease

removal efficiency have been shown to

be 90–95 percent). In addition, the

capital and annual operating and

maintenance costs associated with

granular filtration are significantly

higher than the costs of improving gas

flotation systems.

EPA did not select membrane

filtration as a technology basis for this

proposed rule because it has not been

sufficiently demonstrated as available to

support national effluent limitations at

this time. Membrane filtration is a

commercially demonstrated technology

in other industries and several

manufacturers have been developing

this technology for use in treating

produced water. Although not yet

available to the oil and gas industry,

some operators have shown interest in

the technology and limited testing of

these systems has taken place. In

developing the final limitations for the

offshore subcategory, EPA determined

that because of operational problems

(e.g., fouling of the membrane, actual

treatment capacity less than design

capacity) this technology did not

support use as a technology basis for

final effluent limitations. (See 58 FR

12481; March 4, 1993.) In the absence of

any data to the contrary, EPA believes

that this technology still is not available

for full-scale systems capable of longterm, effective treatment of produced

water.

In evaluating reinjection of produced

water, EPA noted that a number of

coastal oil and gas sites were using

cartridge filters as part of the treatment

system. EPA collected wastewater

samples to characterize the efficacy of

cartridge filtration to determine whether

this technology should serve as a basis

for effluent limitations and standards.

EPA’s evaluation of cartridge filtration

performance data indicates that this

technology is capable of providing oil

and grease removal only marginally

better than that currently required by

the existing BPT effluent limitations. In

addition, EPA’s evaluation did not

identify any significant removals of the

priority and nonconventional pollutants

present in produced water. Thus,

cartridge filtration was not selected as a

basis for limiting produced water

discharges.

3. Injection

EPA also considered using injection

technology as a basis for setting a more

stringent requirement under this rule.

With the exception of Cook Inlet,

injection of produced water is widely

practiced by facilities in the coastal

subcategory as well as in the onshore

subcategory. Injection technology for

produced water consists of injecting it,

under pressure, into Class II UIC wells

into underground formations. This

option results in no discharge of

produced water to surface waters.

Treatment of the produced water prior

to injection is usually necessary, and

such treatment often includes removal

of oil and suspended matter by BPT oil

separation technology followed by

filtration technology. The removal of

suspended matter prior to injection is

required to prevent pressure build-up

and plugging of the receiving formation

and/or to protect injection pumps from

damage.

While EPA determined that filtration

was not a technology appropriate for

serving as the basis for control of

effluent prior to discharge, filtration was

considered relevant technology for use

as pretreatment prior to injection, thus,

it is included as part of the basis for the

injection technology option. EPA

determined from information gathered

on site visits in the Gulf coast area, as

well as from industry contacts, that

cartridge filtration is generally used

following BPT oil/water separation

technologies at injecting facilities

accessible by water only. For facilities

accessible by land, it was determined

that rather than pretreat produced water

using filtration, it is more cost effective

to perform periodic well workovers on

the injection well to remove clogged

material from the wellbore. However,

for facilities treating produced water

flows greater than 64,000 bpd, EPA

determined that it would be more

appropriate to employ granular filtration

after BPT separation technology because

it is more cost effective to use this

technology for higher flows rather than

cartridge filtration.

4. Other Technologies

In developing effluent limitations for

the offshore subcategory, EPA also

considered other technologies such as

carbon adsorption, biological treatment,

chemical precipitation, and

hydrocyclones. (See 56 FR 10688;

March 13, 1991.) Carbon adsorption was

rejected as a technology basis because

the limited use of this technology did

not give sufficient performance data to

enable a full evaluation. Biological

treatment was rejected because of

problems associated with biologically

treating the high dissolved solids (brine)

waters. Operational problems and an

inability to quantify reductions of

priority pollutant metals led to rejection

of chemical precipitation.

Hydrocyclones were rejected as a

technology basis for BAT/NSPS effluent

limits because the performance data

available demonstrated only that it was

capable of meeting existing BPT limits

for oil and grease, and data were lacking

regarding removals of priority

pollutants. EPA has not received any

new information regarding treatment

efficacy (as measured by priority

pollutant removal) for these

technologies, and is not aware of any

information which would support

conclusions different than those made

for the Offshore Guidelines.

5. Options Considered

Five options were considered by EPA

in developing BCT, BAT, NSPS, PSES

and PSNS limitations for produced

water. These options were based on

either injection, improved gas flotation,

or a combination of these technologies.

The 5 options are listed below with

limitations for oil and grease associated

with the options allowing discharges:

Option 1—(BPT All): EPA has

included as an option setting effluent

limitations equal to the existing BPT

requirements. Oil and grease would be

limited in the effluent at 48 mg/l

monthly average, and 72 mg/l daily

maximum.

Option 2—(Improved Flotation All):

All discharges of produced water would

be required to meet limitations on oil

and grease content of 29 mg/l 30-day

average and a daily maximum of 42 mg/

l. The technology basis for these limits

is improved operating performance of

gas flotation. The specific numerical

limit of 29 mg/l 30-day average and 42

mg/l (daily maximum) are based on the

statistical analyses of performance of
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9451

improved gas flotation conducted to

develop oil and grease limits for the

Offshore Guidelines. (See 58 FR 12462,

March 4, 1993).

Option 3—(Zero Discharge; Cook Inlet

BPT): With the exception of facilities in

Cook Inlet, all coastal oil and gas

facilities would be prohibited from

discharging produced water. Coastal

facilities in Cook Inlet would be

required to comply with existing BPT

effluent limitations (48/72 mg/l

described above) for oil and grease.

Option 4—(Zero Discharge; Cook Inlet

Improved Flotation): With the exception

of facilities in Cook Inlet, all coastal oil

and gas facilities would be prohibited

from discharging produced water.

Coastal facilities in Cook Inlet would be

required to comply with the oil and

grease limitations of 29 mg/l 30-day

average and 42 mg/l daily maximum

based on improved operating

performance of gas flotation and the

statistical analysis conducted for the

Offshore Guidelines.

Option 5—(Zero Discharge All): This

option would prohibit all discharges of

produced water based using injection.

Specific alternatives have been

developed for Cook Inlet to account for

the different operational practices, and

geological situations that exist at these

platforms. As previously stated, zero

discharge is widely, if not exclusively,

practiced in all coastal areas except

Cook Inlet. Injection of produced waters

is not practiced in Cook Inlet because,

where waterflooding is occurring,

treated seawater is injected instead.

Industry claims that injection of

seawater other than produced water for

enhanced recovery is practiced

primarily because injection of produced

water would cause formation fouling.

Industry has claimed that fouling would

occur due to bacteria and scale

formation in produced water, and

otherwise not present in seawater. EPA

has determined that formation fouling

problems associated with produced

water injection are not insurmountable

because filtration and anti-fouling

chemicals can be added prior to

injection, and periodic downhole

workovers can be performed to reopen

clogged formation surfaces.

An additional problem with injecting

produced waters is that no other

formations exist that can accommodate

this wastestream other than the

producing formation. Cook Inlet

operators would experience significant

additional cost associated with piping

produced water if zero discharge was

required from where it is currently

treated to where it could be injected. Of

the 13 producing platforms in the Inlet,

9 of them currently direct their

extracted hydrocarbon fluids to one of 3

land-based separation and treatment

facilities. These land-based facilities

separate the hydrocarbons from the

produced water, treat the produced

water and then discharge it in

accordance with EPA’s Region X’s

NPDES general permit requirements.

The Alaska Oil and Gas Conservation

Commission has confirmed that no

geological formations exist beneath the

land-based facilities that are large

enough to accept the approximately

100,000 barrels per day (bpd) of

produced water generated from these

facilities. Thus, produced water would

be piped back to the platforms for

injection if produced water discharges

were prohibited. The costs for such

piping would comprise 74 percent of

the total costs for injection. This would

be a major cost factor for the Inlet

operations overall since the volume of

produced water being discharged from

these 3 land-based facilities amounts to

approximately 99 percent of that

discharged from all 13 platforms.

6. BCT Options

a. BCT Methodology.

The methodology to determine the

appropriate technology option for BCT

limitations is previously described in

Section VI.A.

b. BCT Cost Test Calculations and

Option Selection.

The five options previously described,

were evaluated according to the BCT

cost reasonableness tests. The pollutant

parameters used in this analysis were

total suspended solids and oil and

grease. All options, except the ‘‘BPT

All’’ option, fail the BCT cost

reasonableness test and thus, EPA

proposes to establish BCT limitations

equal to BPT. Costs for the ‘‘BPT All’’

option are equal to zero because

facilities are complying with the current

BPT limitations. The range of the results

for the POTW test (first part of the BCT

cost test) for the other options is $1.35

to $3.70 per pound of conventional

pollutant removed. Since a value of less

than $0.53 per pound (1992$) is

required to pass the POTW test these

four options fail the first BCT cost test.

Thus, EPA is proposing to establish the

BCT limitations for produced water

equal to BPT (48 mg/l monthly average;

72 mg/l daily maximum). The

calculations for BCT cost reasonableness

test for the produced water options are

described in more detail in Section XI

of the Coastal Technical Development

Document. There are no incremental

non-water quality environmental

impacts associated with the BCT option

because it is equal to BPT.

7. BAT and NSPS Options

EPA has selected Zero discharge;

Cook Inlet improved gas flotation

(Option 4) for the BAT and NSPS level

of control for produced water. A

discussion of the cost and impacts and

a description of the selection rationale

is contained below:

a. Costs.

The cost and pollutant removals

associated with the options considered

for BAT are presented in Table 5.

TABLE 5.—COSTS AND POLLUTANT

REMOVALS FOR PRODUCED WATER

BAT OPTIONS

Option

Costs

(1992$)

(x1000)

Pollutant removals (lbs)

(x1000)

1. BPT all .......... 0 0

2. Improved gas

flotation all ..... 12,400 12,440

3. Zero discharge; cook

inlet BPT ........ 28,600 4,306,800

4. Zero discharge; cook

inlet improved

gas flotation ... 30,860 4,308,300

5. Zero discharge all ....... 49,700 5,484,800

These estimates are presented

incremental to the baseline of current

industry operating practices which is

equal to BPT where discharges are

occurring. Thus, as shown on Table 5,

costs attributable to Option 1, which is

equal to BPT, is zero. On January 9,

1995 (60 FR 2387), EPA promulgated

general NPDES permits that would

prohibit discharges of produced water

from coastal facilities in Texas and

Louisiana. For the purpose of this

proposal, EPA’s compliance cost

estimates and economic impact

assessments are determined without

considering this permit. Had EPA’s

costing estimates assumed that the

general permit would be in effect, the

total estimated cost of the proposed

BAT limitations for produced water for

the entire coastal subcategory would be

$10.4 million instead of $30.9 million

annually.

In developing the costs of zero

discharge for this option, EPA

determined, based on Texas and

Louisiana state permit data, the number

and volume of produced water

discharges that would be discharging by

the time this final rule is scheduled to

be signed July 1996. This investigation

identified, by operator and oil and gas

field, 216 produced water separation/

treatment facilities that would be

discharging approximately 180 million

barrels per year (bpy) in Texas and
9452 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

Louisiana as of July 1996. Costs are

calculated without taking into account

the regulatory effects of the zero

discharge requirement imposed by the

EPA Region VI General Permits (See

Section II.C. of this preamble).

In determining the costs associated

with zero discharge for the Gulf coast

area, EPA utilized the following factors

in the costing analyses:

General

* The only areas that will incur

compliance costs are Cook Inlet in

Alaska, Texas, and parts of Louisiana

since all other coastal areas that have oil

and gas activities currently practice zero

discharge.

For Texas and Louisiana

* Produced water would be injected

into Class II UIC injection wells. The

capacity of each Class II injection well

is 5,000 BPD.

* 90 percent of the injection wells

would be converted from previously

producing wells or dry holes.

* If a discharge is greater than 108

bpd (for water-based facilities) and 71

bpd (for land-based facilities), then the

produced water would be injected

onsite; if the discharge is less than those

flows then it would be more cost

effective to send the produced water

offsite to a commercial facility for

injection. (EPA’s data from Texas and

Louisiana coastal permits show that 77

percent of the produced water

discharges would inject on-site).

* For purposes of estimation, all

Texas separation/treatment facilities are

located on land and all Louisiana

separation/treatment facilities are

located over water. EPA is aware that

this is not entirely the case, i.e. some

facilities in Louisiana are located over

land and some Texas facilities are

located over water. In the absence of

specific location information on all of

the 216 discharging facilities, EPA

determined this to be a good

approximation since the coastal

topography of Louisiana consists of

more extensive wetlands than that of

Texas. (Location is an important factor

when determining the cost of drilling an

injection well, and the cost of produced

water transportation. EPA’s state permit

data base shows that 24 percent of the

produced water discharges are in Texas

and the separation/treatment facilities

are therefore considered to be on land).

* No pretreatment beyond BPT

technology is required prior to injection

for land-based facilities because it is

more cost effective to perform downhole

well workovers twice a year.

Pretreatment beyond BPT treatment

prior to injection consists of cartridge

filtration for water-based facilities. For

flows greater than 64,000 bpd, granular

filtration is used as pretreatment.

* Capital costs are based on sizing

equipment to accommodate future

produced water volume, estimated to be

approximately 1.5 times current flow.

* Where more than one produced

water discharge location exists from one

or more production facilities owned by

the same operator in the same field, EPA

combined the discharges to be injected

into a single injection system. By

combining discharges a savings would

result due to installation of fewer

injection wells.

For Cook Inlet

* No geological formations are

available for produced water injection

except the producing formations.

* No geological formations are

available near or below the existing

onland separation/treatment facilities.

Thus, the produced waters would be

required to be piped back to the

platforms for injection.

* Pretreatment prior to injection

consists of gas flotation and multimedia

filtration. However, operators will use

existing equipment where it currently

exists, and no costs would be incurred

for such existing equipment.

* During the development of this

proposal, industry provided EPA with

information on reservoir plugging and

souring that may result from injecting

produced water in the Cook Inlet. EPA,

in its cost analysis, included costs for

the addition of chemicals that would be

added to the produced water being

injected to alleviate the scaling and

hydrogen sulfide (H2S) formation

problems associated with injection in

this area. Such chemicals include

biocides and scale inhibitors. Annual

workovers must also be performed on

the injection wells.

EPA believes that the cost estimates

are conservative for a number of

reasons. As discussed previously, EPA

determined costs to comply with a zero

discharge requirement in the Gulf of

Mexico based on the number of facilities

that would be discharging after the

expected date of promulgation for this

rule (July 1996). A total of 216 facilities

would still be discharging by then.

However, 28 of these facilities in

Louisiana will be required to cease

discharging by January 1, 1997, because

of the state water quality standard’s no

discharge requirement. Taking this

January 1997 requirement into account

as a portion of the baseline would

further reduce costs by 25 percent.

Furthermore, EPA’s cost estimates for

zero discharge in the Gulf of Mexico are

based on sizing produced water

treatment equipment to accommodate

future produced water volumes

estimated to be approximately 1.5 times

current flow. EPA believes using this

factor, which is standard engineering

practice, has resulted in a conservative

cost estimate overall because many

operators have indicated that they

typically use a factor of 1.2 to 1.25 when

sizing and costing produced water

treatment equipment. Capital costs

would be approximately 12 percent

lower if a factor of 1.2 were used.

Additionally, while EPA’s costing

included combining of operator

discharges for injection within fields,

the analysis showed that costs are not

significantly different if they are not

combined. This is because the high

costs of piping to join discharges closely

equal the costs of individual injection

well installation.

EPA also calculated capital costs of

produced water treatment on the basis

that produced water flows increase the

same for oil as for gas wells. While

produced water volumes from gas

producing wells will generally not

increase at the rate of 1.5, EPA did not

differentiate between the two.

EPA determined that no costs would

be attributed to zero discharge for

California, Florida, Alabama, certain

parts of Louisiana, and the North Slope

of Alaska because operators in these

areas are already practicing zero

discharge of all produced waters.

For improved gas flotation, costs were

estimated based on an evaluation of this

technology during development of the

Offshore Guidelines (58 FR 12463).

Improved performance of gas flotation

units includes improved operation and

maintenance of gas flotation treatment

systems and chemical pretreatment to

enhance system effectiveness. Costs are

based on vendor-supplied data, industry

information, cost analyses conducted by

the Department of Energy, and EPA

projections. Capital and O & M costs

were applied specifically to the coastal

oil and gas operations using nine

modeled flows for land- and wateraccess production facilities. From these

nine modeled flows, EPA conducted

regression analyses to derive cost

equations that would vary based on

flow. These equations were then applied

to the actual 216 discharging facilities to

estimate costs on a site specific basis.

Capital costs include equipment

purchase, installation, and platform or

concrete pad (for land based operations)

retrofit. Operation and maintenance

costs are estimated to be 10 percent of

capital costs.

EPA solicits comments on these costs

and also information regarding the

longitude and latitude locations of
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9453

discharging produced water separation/

treatment facilities in Texas.

The total annual cost of Option 4 for

BAT control of produced water

discharges from existing facilities is

estimated at $30.9 million (1992 dollars)

for the entire coastal subcategory. $29.2

million of this total would be incurred

by operators in the Gulf Coast states of

TX and LA in attaining zero discharge.

The remaining $2.3 million would be

incurred by Cook Inlet operators in

complying with the oil and grease

limitations. EPA finds this cost to be

economically achievable for the reasons

discussed later in Section VII of this

preamble but are briefly summarized

here. Total production losses realized

from this option are expected to total

15.2 million bbls over the lifetime of the

wells and platforms subject to this rule

which equals up to 1.7 percent of total

lifetime production for the Gulf and

Cook Inlet combined. The net present

value losses of producer income

associated with this decrease in

production is $153.2 million. A total of

111 wells in the Gulf coast area (2.4

percent of all current Gulf coast wells)

and no Cook Inlet platforms are

considered likely to shut in immediately

when this proposal becomes final.

Furthermore, a maximum of 12 Gulf

operators might fail as a result of this

BAT option (2.8 percent of the current

Gulf operators). No company failures are

expected in Cook Inlet. This option

would reduce the pollutant loading

from this wastestream by 4.3 billion

pounds per year.

c. Rationale for Selection of BAT.

EPA proposes Zero Discharge; Cook

Inlet Improved Gas Flotation Option 4:

as BAT for produced water. This option

prohibits discharges of produced water

from all coastal facilities, except for

those facilities located in Cook Inlet.

Coastal facilities in Cook Inlet would be

required to comply with the oil and

grease limitations (29 mg/l 30-day

average, 42 mg/l daily maximum) based

on improved operating performance of

gas flotation. EPA has determined this

option to be economically achievable

and technologically available, and that

it reflects the BAT level of control.

Zero discharge is technologically

available because injection of produced

water is currently ongoing in much of

the coastal subcategory at the present

time and adequate geological formations

exist to accept produced water. By 1996,

72 percent of the facilities in the Gulf

region will be meeting zero discharge.

The oil and grease limit applicable to

Cook Inlet is technologically available

for the reasons discussed elsewhere in

this preamble, the record for this rule,

as well as in cited portions of the

rulemaking record for the Offshore

Guidelines.

Option 4 is economically achievable

because, as the economic analysis

shows (in Section VII), total production

losses in terms of oil production as a

result of this proposed rule are expected

to range between 1.0 percent and 1.7

percent of total lifetime production for

both Cook Inlet and the Gulf.

Additionally, only 2.4 percent of all

current Gulf coastal wells (111 out of

4675 current Gulf coastal wells) and no

Cook Inlet platforms are considered

likely to shut in as a result of this rule.

These shut-in wells tend to be relatively

low-producing and marginal wells. At

most, only 2.8 percent of the operators

in the Gulf (12 of the estimated 435 Gulf

coastal operators) might fail as a result

of a zero discharge requirement and no

firm failure is expected in Cook Inlet, as

a result of meeting oil and grease limits

of 29 mg/l 30-day average and 42 mg/

l daily maximum for produced water.

(The range of firm failures in the Gulf

is actually 0-12, but because data were

not available to rule out the possibility

of failures, EPA assumed possible

failures to be actual failures.) The

‘‘average’’ Gulf coastal firm does not

discharge produced water and coastal

firms are expected to face average

(medium) declines in equity or working

capital of 0 percent. Of the 122

discharging firms, average (medium)

declines in equity or working capital of

0.37 percent and 2.63 percent,

respectively, are expected to occur.

These impacts, combined with the fact

that most Gulf coastal operators (72

percent) will not be discharging by

1996, show Option 4 to be economically

achievable.

Option 5, zero discharge all was not

selected based on the unacceptable

economic impacts estimated for the

Cook Inlet operators. EPA’s economic

analysis shows that 3 of 13 platforms

would be ‘‘shut-in’’ or closed down and

believes that this economic impact is

unacceptable in Cook Inlet. EPA did not

select the ‘‘Flotation All’’ or ‘‘BPT All’’

options as preferred because they,

applied industry-wide, do not represent

BAT or NSPS level of control. As stated

previously, all coastal operations in

California, Alabama, Florida, some parts

of Louisiana and the North Slope of

Alaska do not discharge produced

water, but inject their produced water

underground either to comply with

permit limitations or to enhance

hydrocarbon recovery. EPA has

therefore concluded that control options

based on the continued discharge of

produced water in all areas of the

country do not represent BAT or NSPS.

Non-water quality environmental

impacts for the proposed Option 4

consist of incremental air emissions of

approximately 2800 tons/year across the

entire subcategory. Given that an

average Gulf coast production facility

may alone produce approximately 188

tons/year of emissions, this option

would increase air emissions by about

13 percent. EPA considers this increase

to be acceptable. A description of

estimated non-water quality impacts,

consisting of additional energy

requirement and air emission created by

complying with the proposed

requirements and other options being

considered are discussed in Section VIII

of this preamble and in more detail in

Chapter XIV of the Coastal Technical

Development Document.

d. Rationale for Selection of NSPS.

For NSPS control of produced water

discharges from new sources, EPA is

proposing the ‘‘Zero Discharge All’’

(Option 5) prohibiting discharges of

produced water from all new sources.

Option 5 is economically achievable for

the reasons discussed in the economic

impact analysis and in Section VII,

below. This NSPS option is estimated to

cost approximately $4.5 million

annually for the entire coastal

subcategory. This cost would be

incurred only by Gulf Coast operators

where EPA estimates that approximately

6 new production facilities will be

constructed per year. No new sources

are expected in the Cook Inlet (See

Section VII). However, were new

sources to be installed in Cook Inlet, the

preferred NSPS option of zero discharge

is not expected to cause a barrier to

entry because new project operations

would still be quite profitable. For a

new source, EPA estimates that the

decline in internal rates of return would

only be reduced from 39 to 37 percent

and therefore would not be likely to

affect the decision to undertake a new

project. In addition, the impact on Net

Present Value from the zero discharge

requirement (2.9 percent) is not

substantially different from the impacts

on Net Present Value from the proposed

BAT option for Cook Inlet platforms (2.4

percent). Thus existing and new

platforms would face similar impacts on

Net Present Value and Internal Rate of

Return. In addition, as discussed in

Section VIII, EPA has determined the

non-water quality environmental

impacts to be acceptable for the NSPS

option for produced water. Total

incremental emissions from the

proposed option is approximately 64

tons/year for NSPS. As a comparison, an

average Gulf coast production facility

may produce approximately 188 tons/

year of emissions. EPA considers this
9454 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

increase in non-water quality impacts to

be acceptable.

8. PSES and PSNS Options Selection

Based on the 1993 Coastal Survey and

other information reviewed as part of

this rulemaking, EPA has not identified

any existing coastal oil and gas facilities

which discharge produced water to

publicly owned treatment works

(POTWs), nor are any new facilities

projected to direct their produced water

discharge in such manner. However,

because EPA is proposing a limitation

requiring zero discharge for those

existing facilities, there is the potential

that some facilities may consider

discharging to POTWs in order to avoid

the BAT and /or NSPS limitations.

Pretreatment standards for produced

water are appropriate because EPA has

identified the presence of a number of

toxic and nonconventional pollutants,

many of which are incompatible with

the biological removal processes at

POTWs. Large concentrations of

dissolved solids in the form of various

salts in the produced water cause the

discharge to POTWs to be incompatible

with the biological treatment processes

because these ‘‘brines’’ can be lethal to

the organisms present in the POTW

biological treatment systems. (See the

Coastal Technical Development

Document for detailed information on

produced water characterization.) EPA

does not have sufficient data for

conducting a pass through analysis for

reasons discussed further in the Coastal

Technical Development Document. EPA

solicits data and comment on this

particular issue.

EPA is proposing to require

pretreatment standards for existing and

new sources (PSES and PSNS,

respectively) that would prohibit the

discharge of produced water. The

technology basis for compliance with

PSES and PSNS would be the same as

that for BAT and NSPS zero discharge

limits. The cost projections for both

PSES and PSNS are considered to be

zero since no existing sources discharge

to POTW’s and there are no known

plans for new sources to be installed in

locations amenable to sewer hookup.

Also, because no facilities are

discharging to POTW’s EPA proposes

that PSES and PSNS requiring zero

discharge be effective as of the effective

date of this rule. Because zero discharge

for new sources is economically

achievable, the costs of complying with

zero discharge would not be a barrier to

entry. Non-water quality environmental

impacts would be similar to those for

new sources, which EPA has found to

be acceptable. Thus, EPA has

determined that pretreatment standards

for new sources that are equal to NSPS

are economically achievable and

technologically available for PSNS and

that the non-water quality

environmental impacts are acceptable.

C. Produced Sand

1. Waste Characterization

Produced sand consists primarily of

the slurried particles that surface from

hydraulic fracturing and the

accumulated formation sands and other

particles (including scale) generated

during production. Produced sand is

generated during oil and gas production

by the movement of sand particles in

producing reservoirs into the wellbore.

The generation of produced sand

usually occurs in reservoirs comprised

of geologically young, unconsolidated

sand formations. The produced sand

wastestream is considered a solid and

consists primarily of sand and clay with

varying amounts of mineral scale and

corrosion products. This waste stream

may also include sludges generated in

the produced water treatment system,

such as tank bottoms from oil/water

separators and solids removed in

filtration.

Produced sand is carried from the

reservoir to the surface by the fluids

produced from the well. The well fluids

stream consists of hydrocarbons (oil or

gas), water, and sand. At the surface, the

production fluids are processed to

segregate the specific components. The

produced sand drops out of the fluids

stream during the separation process

and accumulates at low points in

equipment. Produced sand is removed

primarily during tank cleanouts.

Because of its association with the

hydrocarbon stream during extraction,

produced sand is generally

contaminated with crude oil or gas

condensate.

Produced sand samples were obtained

during EPA’s sampling visits to 10

production facilities. Analysis of these

samples showed oil and grease

concentrations of 205 g/Kg. All toxic

metals were present except silver, with

most notable contributions from copper

(32.15 mg/Kg) and lead (171.94 mg/Kg).

Naturally Occurring Radioactive

Material (NORM) was present at an

average of 8.9 pCi/g in the samples

which were taken from coastal facilities

in the Gulf of Mexico. Toxic organics

present were similar to those found in

produced water including benzene,

ethylbenzene, xylene, toluene,

propanone and phenanthrene. All 10

sites disposed of the produced sands at

commercial facilities. Produced sand

volumes vary from well to well and are

a function of produced water

production, formation type, and well

completion methods. Maximum

produced sand volumes (out of these 10

sites) was 400 bpy per production

facility. The 1993 Coastal Survey results

showed that average volumes of

produced sand ranged from 36 to 94 bpy

per facility. Additional discussion of

produced sand is presented in the

Coastal Technical Development

Document.

2. Selection of Pollutant Parameters

EPA is proposing to control all

pollutants present in produced sand by

prohibiting discharge of this

wastestream.

3. Control and Treatment Technologies

No effluent limitations guidelines

have been promulgated for discharges of

produced sand in the coastal

subcategory. The final NPDES permits

for Texas, Louisiana, and the existing

state NPDES permits for Alabama

contain a zero discharge limit for

produced sand.

Data from the 1993 Coastal Oil and

Gas Questionnaire indicate that the

predominant disposal method for

produced sand is landfarming, with

underground injection, landfilling, and

onsite storage also taking place to some

degree. Because of the cost of sand

cleaning, in conjunction with the

difficulties associated with cleaning

some sand sufficiently to meet existing

permit discharge limitations, operators

use onshore (onsite or offsite) or

downhole disposal. In fact, only one

operator was identified in the 1993

Coastal Oil and Gas Questionnaire as

discharging produced sand in the Gulf

of Mexico, but this operator also stated

that it planned to cease its discharge in

the near future. All Cook Inlet operators

submitted information stating that no

produced sand discharges are occurring

in this area.

4. Options Considered and Rationale for

Options Selection

The only option considered is zero

discharge of produced sands. Because

current industrial practice for the

coastal subcategory is predominately

zero discharge, EPA considered this the

appropriate option for this wastestream.

The zero discharge requirement would

eliminate the discharge of toxic

pollutants present in produced sand.

Because the industry practice of zero

discharge is already so widespread, the

zero discharge limitation will result in

minimal increased cost to the industry.

EPA is proposing to set BPT, BCT,

BAT and NSPS equal to zero discharge

for produced sand. EPA has determined

that zero discharge reflects the BPT,
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9455

BCT, BAT and NSPS levels of control

because, as it is widely practiced

throughout the industry, it is both

economically achievable and

technologically available. Zero

discharge for NSPS would not cause a

barrier to entry because, since it is equal

to current practice, it will impose no

cost. Zero discharge will have negligible

economic impacts on the industry. As

zero discharge reflects current practice,

there are negligible incremental nonwater quality environmental impacts

from this option. Since proposed BCT

would be set equal to the proposed BPT,

there is no cost of BCT incremental to

BPT. Therefore, this option passes the

BCT cost reasonableness tests.

The technology basis for compliance

with PSES and PSNS is the same as that

for BAT and NSPS. EPA proposes

pretreatment standards for produced

sands equal to zero discharge because,

like drilling fluids and cuttings, their

high solids content would interfere with

POTW operations. Because EPA is not

aware of any produced sands being sent

to POTWs, this requirement is not

expected to result in operators incurring

costs. Zero discharge for PSNS would

not cause a barrier to entry for the same

reasons as discussed above for NSPS.

There are no additional non-water

quality environmental impacts

associated with this requirement

because it reflects current practice.

D. Deck Drainage

1. Waste Characterization

Deck drainage consists of

contaminated site and equipment runoff

due to storm events and wastewater

resulting from spills, drip pans, or

washdown/cleaning operations,

including washwater used to clean

working areas. Deck drainage is

generated during both the drilling and

production phases of oil and gas

operations. Currently, approximately

11.5 million bpy of deck drainage are

discharged by facilities in the coastal

subcategory. EPA estimates that 112,000

pounds of oil and grease are discharged

in this wastestream annually. In

addition to oil, various other chemicals

used in drilling and production (actual

hydrocarbon extraction) operations may

be present in deck drainage. Limited

treated effluent data are available for

this wastestream, however, EPA has

identified the presence of organic and

metal priority pollutants in deck

drainage. EPA’s analytical data for deck

drainage comes from the data acquired

during the development of the Offshore

Guidelines. EPA conducted a three

facility sampling program (described in

Section V of the Offshore Technical

Development Document) during which

samples were taken of untreated deck

drainage. Eight of the toxic metals were

detected, most notably lead (ranging in

concentration from 25 - 352 ug/l) and

zinc (ranging in concentration from

2970–6980 ug/l). Priority organics were

also present including benzene, xylene,

naphthalene and toluene. Other

nonconventional pollutants found in

deck drainage include aluminum,

barium, iron, manganese, magnesium

and titanium.

The content and concentrations of

pollutants in deck drainage can also

depend on chemicals used and stored at

the oil and gas facility. An additional

study on deck drainage from Cook Inlet

platforms, reviewed during

development of the Offshore Guidelines,

showed that discharges from this

wastestream may also include paraffins,

sodium hydroxide, ethylene glycol,

methanol and isopropyl alcohol.

(Dalton, Dalton, and Newport,

Assessment of Environmental Fate and

Effects of Discharges from Oil and Gas

Operations, March 1985.)

2. Selection of Pollutant Parameters

EPA has selected free oil as the

pollutant parameter for control of deck

drainage. The specific conventional,

toxic and nonconventional pollutants

found to be present in deck drainage are

those primarily associated with oil, with

the conventional pollutant oil and

grease being the primary constituent. In

addition, other chemicals used in the

drilling and production activities and

stored on the structures have the

potential to be found in deck drainage.

EPA believes that an oil and grease

limitation together with incorporation of

site specific Best Management Practices,

as required under the stormwater

program and as discussed below, will

control the pollutants in this

wastestream.

The specific conventional, toxic, and

nonconventional pollutants controlled

by the prohibition on the discharges of

free oil are the conventional pollutant

oil and grease and the constituents of oil

that are toxic and nonconventional

pollutants (see previous discussion in

Section VI.B. describing the chemical

constituents of oil). EPA has determined

that it is not technically feasible to

control these toxic pollutants

specifically, and that the limitation on

free oil in deck drainage reflects control

of these toxic pollutants at the BAT and

BADCT (NSPS) levels.

3. Control and Treatment Technologies

a. Current Practice.

BPT limitations for deck drainage

prohibit the discharge of free oil. All

equipment and deck space exposed to

stormwater or washwater are

surrounded with berms or collars. These

berms capture the deck drainage where

it flows through a drainage system

leading to a sump tank. Initial oil/water

separation takes place in the sump tank

which is generally located beneath the

deck floor or underground at land-based

operations. Effluent from the sump tank

may be directed to a skim pile, where

additional oil/water separation occurs.

(The skim pile is essentially a vertical

bottomless pipe with internal baffles to

collect the separated oil.)

The deck drainage treatment system is

a gravity flow process, and the treatment

tanks generally do not require a power

source for operation. Thus, deck

drainage generated at operations located

in powerless, remote situations, (such as

satellite wellheads) can be effectively

treated.

The difficulties in obtaining a

representative sample of deck drainage

effluent (due to their submerged or

underground location) preclude the use

of the static sheen test for this

wastestream. Thus, free oil is measured

by the visual sheen test. Deck drainage

treatment is discussed in more detail in

the Coastal Technical Development

Document.

b. Additional Technologies

Considered.

EPA knows of no additional

technologies for the treatment of deck

drainage. However, EPA, as described in

the proceeding section, has determined

that deck drainage could in some

circumstances be commingled with

either produced water or drill fluids and

thus, could become subject to the

limitations imposed on these major

wastestreams. EPA has also considered

requiring best management practices

(BMPs) on either a site-specific basis or

as part of the Coastal Guidelines (See

discussion under part 6.b. in this

Section).

4. Options Considered

EPA has developed two options for

the control of deck drainage. These are

(1) establish limitations equal to BPT; or

(2) establish limitations for the ‘‘first

flush’’ of deck drainage equal to those

for the major wastestreams it can be

commingled with, and limitations equal

to BPT after the first flush.

In addition to BPT technology

described above, EPA examined

additional treatment control options

based on current industrial practices.

The 1993 Coastal Oil and Gas

Questionnaire as well as the industry

site visits reveal that deck drainage is

often commingled with produced waters

prior to discharge or injection. Because
9456 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

of this practice, EPA investigated an

option requiring capture of the ‘‘first

flush’’, or most contaminated portion of,

deck drainage. Depending on whether

the deck drainage is generated from

drilling or production (actual

hydrocarbon extraction) operations, this

first flush would be subject to the same

limitations as would be imposed on

either produced water or drilling fluids

and cuttings based on the assumption

that these two wastestreams could be

commingled. Thus, for deck drainage

during production, EPA considered as

an option zero discharge for the first

flush everywhere except in Cook Inlet,

where oil and grease limitations would

apply. Zero discharge would be required

for the first flush captured at drilling

operations everywhere. After capturing

the first flush, BPT limitations would

apply to any remaining deck drainage at

either production or drilling operations.

Capture of all of deck drainage to meet

zero discharge requirements would be

impractical due to relatively heavy

precipitation that occurs in the Gulf

areas.

EPA considered employing a 500

barrel tank to capture the first flush. A

tank of this size would be installed at

production facilities, and would provide

enough storage capacity to capture most,

if not all, of the rainfall generated

during a 3.5 inch rainfall event at an

average size facility. Tanks smaller than

500 bbls would not be large enough to

effectively capture the first flush of

contaminated drainage. Tanks larger

than this would be too costly to install.

A 3.5 inch, 24 hour rainfall event would

generally only be exceeded once per

year in southern Louisiana (the coastal

area receiving the most rainfall), and at

most, two to three times. After

collection, the 500 barrels (or less

depending on the size storm event) of

deck drainage would be directed

through the produced water treatment

and would be subject to the same

limitations as required for produced

water.

For drilling operations, the first 500

barrels would be subject to zero

discharge. The basis for this

requirement would be that the deck

drainage would be directed to on-site

drilling waste collection vessels or

levees where they would be sent off-site

for commercial disposal.

After collection and treatment of the

first 500 bbls of deck drainage, any

remaining discharge would be subject to

the BPT limitations on free oil as

measured by the visual sheen test.

The first flush option for deck

drainage is estimated to eliminate

discharge of more than 9 million bpy of

deck drainage (about 78 percent of the

total currently discharged) resulting in

the removal 82,000 pounds per year of

oil and grease.

5. BCT Option Selection

EPA conducted the BCT cost test

(described previously in Section VI) for

the two deck drainage options. The first

flush option did not pass the POTW cost

test. The result of this test analysis

ranged from $2.13 to $3.45 per pound,

and to pass the test, this value must be

less than $0.534 per pound.

Thus, EPA has selected BPT, or a

limitation prohibiting the discharge of

free oil as the BCT limit, for deck

drainage. This is a no-cost option

because it reflects current practice. It is

cost reasonable under the BCT cost test

because the POTW test result and the

industry cost-effectiveness test results

are both zero (and therefore pass their

respective tests).

6. Rationale for Selection BAT, NSPS,

PSES and PSNS

a. Cost.

No costs are incurred by compliance

with the option to require BPT limits for

deck drainage. Costs to comply with the

first flush option for operations in the

Gulf of Mexico would be approximately

$13.5 million per year. This includes

the costs for both production and

drilling operations to comply with a

zero discharge requirement for the first

flush followed by BPT for any

remaining discharge after that. Costs to

comply with this option for the Cook

Inlet would be approximately $699,000

per year. This includes the costs of

treating the first flush of deck drainage

with produced water to meet oil and

grease limitations of 29 mg/l 30-day

average, and 42 mg/l daily maximum,

followed by BPT for any remaining

discharge after that. Total costs for this

option would be approximately $14.2

million per year.

b. Rationale for Selection of BAT and

NSPS.

EPA has selected BPT as its preferred

option for BAT and NSPS for deck

drainage. Since free oil discharges are

already prohibited under BPT, there are

no incremental compliance costs,

pollutant removals, or non-water quality

environmental impacts associated with

this control option. Since this preferred

option limits free oil equal to existing

BPT standards, it is technologically

available and economically achievable.

EPA has rejected the first flush option

for control of deck drainage for several

reasons primarily relating to whether

this option is technically available to

operators throughout the coastal

subcategory. Deck drainage is currently

captured by drains and flows via gravity

to separation tanks below the deck floor.

However, the problems associated with

capture and treatment beyond gravity

feed, power independent systems, are

compounded by the possibilities of

back-to-back storms which, may cause

first flush overflows from an already full

500 bbl tank. In addition, tanks the size

of 500 barrels are too large to be placed

under deck floors. Installation of a 500

bbl tank would require construction of

additional platform space, and the

installation of large pumps capable of

pumping sudden and sometimes large

flows from a drainage collection system

up into the tank. The additional deck

space would add significantly,

especially for water-based facilities, to

the cost of this option. Further, many

coastal facilities are unmanned and

have no power source available to them.

Deck drainage can be channelled and

treated without power under the BPT

limitations.

Capturing deck drainage at drilling

operations poses additional technical

difficulties. Drilling operations on land

may involve an area of approximately

350 square feet. A ring levee is typically

excavated around the entire perimeter of

a drilling operation to contain

contaminated runoff. This ring levee

may have a volume of 6,000 bbls,

sufficient to contain 500 bbls of the first

flush. However, collection of these 500

bbls when 6,000 bbls may be present in

the ring levee would not effectively

capture the first flush. Costs to install a

separate collection system including

pumps and tanks, would add

significantly to the cost of this option.

While costs are significant, the

technological difficulties involved with

adequately capturing deck drainage at

coastal facilities is the principal reason

why this option was not selected. EPA

has selected the option requiring no

discharge of free oil for BAT and NSPS

control of deck drainage. EPA has

determined that these limitations and

standards properly reflect BAT and

NSPS levels of control. EPA did not

identify any other available technology

for this waste stream. EPA solicits

comments on the existence and

practicality of treatment systems other

than BPT.

EPA’s proposed option does not

include best management practices

(BMPs) for this wastestream as part of

these guidelines. EPA currently believes

that current industry practices, in

conjunction with the requirements as

proposed in the proposed general

stormwater rule (58 FR 61262-61268,

November 19, 1993), would be sufficient

to minimize the introduction of

contaminants to this wastestream to the

extent possible. These stormwater
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9457

requirements, if promulgated as

proposed, would require an oil and gas

operator to develop and implement a

site-specific storm water pollution

prevention plan consisting of a set of

BMP’s depending on specific sources of

pollutants at each site. As noted in the

stormwater proposal, the two types of

BMP’s most effective in reducing storm

water contamination are to minimize

exposure (e.g., covering, curbing, or

diking) and treatment type BMP’s which

are used to reduce or remove pollutants

in storm water discharges (e.g., oil/water

separators, sediment basins, or

detention ponds).

EPA solicits comment as to whether

BMPs should be required for deck

drainage as part of the Coastal

Guidelines. Such BMPs may include (1)

segregation of deck drainage from oil

leaks from pump bearings and seals by

using drip pans and other collection

devices, (2) segregation of contaminated

process area deck drainage and runoff

from relatively uncontaminated runoff

from areas such as living quarters, and

walkways, (3) installation of roofs and

sheds to divert uncontaminated rainfall

from areas with a high potential for

generating contaminated runoff, (4)

careful handling of drilling fluid

materials and treatment chemicals to

prevent spills, (5) use of local

containment devises such as liners,

dikes and drip pans where chemicals

are being unpackaged and where wastes

are being stored and transferred.

7. PSES and PSNS

EPA is proposing to limit PSES and

PSNS for deck drainage as zero

discharge. EPA believes that zero

discharge for PSES and PSNS is

preferable to establishing a limit equal

to BPT because generally slugs of deck

drainage would interfere with biological

treatment processes at POTW’s. This is

discussed further in the Coastal

Technical Development Document. In

addition, EPA did not have sufficient

data to conduct a pass through analysis

of the pollutants found in deck drainage

for the reasons discussed further in the

Coastal Technical Development

Document. EPA solicits comments and

data on this issue. Moreover, technical

difficulties associated with capture of

deck drainage that make it difficult to

require limitations other than the BPT,

no free oil limit makes it unlikely that

this wastestream would be sent to

POTW’s. EPA solicits comment on

whether it would be possible for

collection of deck drainage and

transmission to a POTW to occur.

E. Treatment, Workover, and

Completion Fluids

1. Waste Characterization

Well treatment, workover, and

completion fluids are primarily

generated during production. Well

treatment and workover fluids are

inserted downhole in a producing well

to increase a well’s productivity or to

allow safe maintenance of the well.

Completion fluids are also inserted

downhole after a well has been drilled,

and serve to clean the wellbore, and

maintain pressure prior to production.

In most operations, these fluids

resurface once production is initiated

and can either be reused, or must be

disposed of.

According to results obtained in the

1993 Coastal Oil and Gas Questionnaire,

EPA estimates that approximately

275,000 bbls (205,000 and 70,000 bpy of

treatment/workover and completion

fluids respectively) or these fluids are

discharged annually from coastal oil

and gas operations in Texas and

Louisiana. This amounts to an average

of 587 bbls of treatment and workover

fluids discharged per year, per well,

from approximately 350 wells. For

completion fluids, this amounts to an

average of 209 bbls discharged per year

per well from 334 wells. The 1993

Questionnaire also provides information

showing that treatment, workover and

completion fluids discharged are

commingled with the produced water in

Texas and Louisiana prior to injection

or discharge. Florida, Alabama and

North Slope coastal oil and gas

operators do not discharge these fluids.

Based on the 1993 Coastal Oil and Gas

Questionnaire and EPA’s Region X

Discharge Monitoring Reports

(described in Section V) all Cook Inlet

operators commingle these fluids with

produced water for treatment prior to

discharge.

The composition of the discharges is

highly dependent on the fluid’s

purpose, but they generally consist of

acids (in the case of treatment) or

weighted brines (for workover of

completion). The principal pollutant in

these fluids is oil and grease ranging in

concentration from 15–722mg/l. Total

suspended solids, another major

constituent in these fluids, is present in

concentrations ranging from 65 to 1600

mg/l. Prominent priority metals that

exist in these wastes include chromium,

copper, lead, and zinc. Priority organics

are also present including acetone,

benzene, ethylbenzene, xylene, toluene,

and naphthalene.

EPA estimates that, approximately

22,000 pounds of oil and grease, 50,000

pounds of TSS, 292 pounds of toxic

metals, and 417 lbs of toxic organics are

being discharged annually in the Gulf of

Mexico. In addition, approximately 3.4

million pounds of nonconventionals are

being discharged including boron,

calcium, cobalt, iron, manganese,

molybdenum, tin, vanadium, and

yttrium.

2. Selection of Pollutant Parameters

Where zero discharge would be

required, EPA would be regulating all

conventional, toxic, and nonconventional pollutants found in well

treatment, completion and workover

fluids.

In Cook Inlet, where discharge would

be allowed under Option 2, the

parameter ‘‘oil and grease’’ would be

regulated as an indicator for toxic

pollutants. EPA has data indicating that

the control of oil and grease will control

certain toxic pollutants (including

phenol, naphthalene, ethylbenzene,

toluene and zinc) as discussed in the

Offshore Technical Development

Document. As presented in Section VI

of the Offshore Technical Development

Document when discussing the

prohibitions on the discharge of free oil,

removal of oil from the discharge

effectively removes certain toxic

pollutants. Free oil is considered to be

‘‘indicator’’ for the control of specific

toxic pollutants present in complex

hydrocarbon mixtures. These pollutants

include benzene, toluene, ethylbenzene,

naphthalene, phenanthrene, and

phenol.

Under EPA’s proposed BCT limits,

applicable to conventional pollutants,

EPA would prohibit the discharge of

‘‘free oil,’’ as determined by the static

sheen test. EPA would prohibit

discharge of ‘‘free oil’’ as a surrogate for

control over the conventional pollutant

‘‘oil and grease’’ in recognition of the

complex nature of the oils present in

drilling fluids, including crude oil from

the formation being drilled.

As will also be discussed below, EPA

has determined that it is not feasible to

regulate separately each of the

constituents in these fluids because

these fluids in most instances become

part of the produced water wastestream

and take on the same characteristics as

produced water. Due to the variation of

types of fluids used, the volumes and

their correspondingly variable

constituent concentrations, EPA

believes it is impractical to measure and

control each individual parameter.

While the oil and grease and, in

certain instances, the no free oil

limitations limit the discharges of toxic

and conventional pollutants found in

well treatment, completion and

workover fluids, certain other pollutants
9458 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

are not controlled. EPA proposes to

exercise its discretion not to regulate

these pollutants because EPA has not

detected them in more than a very few

of the samples within the subcategory

and the pollutants when found are

present in trace amounts not likely to

cause toxic effects. This is consistent

with EPA’s findings in the Offshore

Guidelines. (See EPA’s data base for

these fluids in the Coastal Technical

Development Document).

3. Control and Treatment Technologies

Current practice in the control of

discharges from these fluids is to meet

the BPT limitations of no free oil (using

the visual sheen test). EPA’s final

general permit applicable to the

discharges from coastal oil and gas

drilling operations in Texas and

Louisiana further prohibits discharges of

treatment, workover and completion

fluids to freshwater areas. Methods for

treatment and discharge, reuse or

disposal include:

* Treatment and disposal along with

the produced water

* Neutralization for pH control and

discharge to surface waters

* Reuse

* Onshore disposal and/or treatment

and discharge in coastal or offshore

areas.

4. Options Considered

EPA has considered two options for

the treatment of treatment, workover,

and completion fluids. These are (1)

Prohibit the discharges of free oil (equal

to the BPT limits) and prohibit the

discharges of these fluids to freshwaters

of Texas and Louisiana, (2) Limit the

discharges equal to EPA’s preferred

options for produced waters. For

produced water BAT limits, EPA is

proposing zero discharge everywhere

except Cook Inlet, where the proposed

produced water control option is to

meet limitations on oil and grease of 42

mg/l daily maximum and 29 mg/l 30-

day average. For NSPS, PSES, and

PSNS, EPA is proposing zero discharge

everywhere for produced water.

There are no additional costs to

comply with Option 1 because it reflects

the current requirements imposed on

the industry.

Option 2 would require for BAT, that

zero discharge be met for treatment,

completion, and workover fluids for all

areas except the Cook Inlet, where

operators are currently commingling

these wastes with produced water, and

would be required to meet oil and

grease limitations of 29 mg/l 30-day

average and 42 mg/l daily maximum.

This would annually remove 72,000

pounds of conventionals, 709 pounds of

priority toxic pollutants and an

additional 3.4 million pounds of

nonconventional pollutants. For NSPS,

EPA would require zero discharge

everywhere, including Cook Inlet. This

would remove annually 9,400 pounds of

conventionals, 92 pounds of priority

toxic pollutants and an additional

440,000 pounds of nonconventional

pollutants. EPA is not applying a

separate cost in Cook Inlet to comply

with this option because these costs are

already included in the costs of

complying with the produced water

option for Cook Inlet (oil and grease

limits of 29 mg/l 30-day average/42 mg/

l daily maximum).

However, for the Gulf, costs attributed

to this option would be operating and

maintenance costs associated with

commingling with produced water and

on-site injection, or hauling off-site to a

commercial disposal facility if

commingling is not possible. In costing

this option for the Gulf, EPA estimated

that 77 percent of treatment, workover

and completion fluids currently being

discharged would be commingled with

produced water. This estimate comes

from information indicating that 77

percent of produced water discharges

are flows greater than 110 bpd (See

Section VI) and would be disposed of by

onsite injection because flows greater

than 110 bpd will be large enough to

accommodate the introduction of

treatment, workover and completion

fluids without fouling the produced

water treatment system. The other 23

percent are less than 110 bpd and

therefore it would be more cost effective

to send the produced waters off-site for

disposal rather than install an injection

well. (See the Coastal Technical

Development Document, Section XII).

Based on these estimates, EPA

calculated the costs of compliance with

Option 2. These costs included

operating and maintenance costs on a

dollar per bbl basis for on-site

commingling and injection with

produced water, and costs of

transportation and disposal for

commercial disposal. The BAT limits

would cost approximately $610,000

annually in the Gulf.

Costs for NSPS requiring zero

discharge for treatment, workover and

completion fluids were calculated based

on EPA’s estimate that 187 new wells

will be drilled per year in the Gulf Coast

(this estimate was obtained from the

1993 Coastal Oil and Gas Questionnaire

results). Of these 187, EPA estimated

that 76 percent (142 facilities) would be

located in Louisiana freshwaters and

would not discharge due to state water

quality standards (this estimate is also

based on the Questionnaire results). The

remaining 45 facilities would each

generate approximately 800 bbls of

treatment, workover and completion

fluids per year. Costs to meet zero

discharge, based on commingling these

fluids with produced water or directing

them separately to commercial disposal

facilities, are estimated to be

approximately $520,000 per year over

the next 15 years. These costs are only

for the Gulf coast operations. No new

sources are expected to be installed in

Cook Inlet.

5. Rationale for Selection of Proposed

Regulations

a. BCT, BAT, and NSPS.

EPA is proposing to establish BCT

limitations equal to BPT, prohibiting the

discharge of free oil in well treatment,

workover, and completion fluids.

Compliance with this limitation would

be determined by the static sheen test.

Since BPT reflects current practice, this

proposed BCT limitation is cost

reasonable under the BCT cost test.

Based on the available data regarding

the levels of conventional pollutants

present in these wastes, EPA did not

identify any other options which would

pass the BCT cost test other than

establishing BCT equal to the existing

BPT limits. Additional information

regarding the results of the BCT cost test

for these wastes is presented in the

Coastal Technical Development

Document. There are no costs or nonwater quality environmental impacts

associated with this proposed BCT

limitation and, since it is equal to BPT,

it is technologically available and

economically achievable.

EPA is co-proposing both options

considered for well treatment,

workover, and completion fluids for

BAT and NSPS. EPA has determined

that both options are technologically

and economically achievable and have

acceptable non-water quality impacts.

However, due to the high cost

effectiveness results for Option 2

(requiring the same limitations as

proposed for produced water) a

preferred option has not been selected.

EPA solicits comment on the

appropriateness of either option. Option

1, which would prohibit the discharge

of free oil and prohibit the discharge of

treatment, workover and completion of

fluids to freshwaters of Texas and

Louisiana, reflects current regulatory

requirements and thus will incur no

additional compliance costs, economic

or non-water quality environmental

impacts. This option would result in no

incremental removal of pollutants from

this wastestream beyond the existing

BPT requirements.
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9459

Option 2 would require for BAT zero

discharge of treatment, completion, and

workover fluids except for Cook Inlet,

where EPA would establish oil and

grease limitations of 29 mg/l 30-day

average, 42 mg/l daily maximum. For

NSPS, this option would require zero

discharge of all treatment, completion,

and workover fluids from all new

sources.

Zero discharge is being achieved by

many operators (except those in Texas,

saline waters of Louisiana, and Cook

Inlet) for the treatment, workover, and

completion fluids wastestream. The

technology basis for zero discharge is

commingling this wastestream with

produced water or sending it separately

to off-site commercial disposal facilities.

For Cook Inlet, this option, which also

contains allowable discharge limitations

is based on commingling with produced

water, because commingling of these

wastestreams is currently occurring in

this area. The specific oil and grease

limits proposed are technologically

available for the same reasons they are

available for control of produced water,

as discussed above.

The zero discharge limitation would

eliminate all discharges of toxic,

conventional, and nonconventional

pollutants. The oil and grease limits

would be technologically based on

improved gas flotation performance (See

Section VI.B. of this preamble) and

serve to limit the discharge of toxic and

conventional pollutants to surface

waters.

Zero discharge for treatment,

workover and completion fluids in Cook

Inlet was not selected for this BAT

option because these fluids are

commingled with produced water as an

integral part of their operations, and

because zero discharge for produced

water was determined to be

uneconomical for Cook Inlet operators.

The costs to meet Option 2 for BAT

($610,000) are relatively minimal since

this amount is negligible in comparison

to total annual production revenue from

Gulf coastal operations.

Costs to achieve zero discharge

everywhere for Option 2 NSPS are

expected to be negligible. Out of the 187

new wells that will be drilled in the

Gulf Coast, 76 percent will not

discharge these fluids in freshwaters

because of water quality standards

requirements. The remaining 45

facilities will each generate

approximately 800 bbls of treatment,

workover and completion fluids per

year (estimates of volumes from the

1993 Coastal Oil and Gas

Questionnaire). While some of these

fluids may be directed for treatment and

disposal to existing production

facilities, EPA is conservatively

estimating costs of the Option 2 NSPS

assuming all of these fluids would be

directed to new production facilities for

treatment and disposal (or be treated onsite at the new source). For the Gulf, the

NSPS requirements under this Option 2

would be the same as those for BAT,

thus costs would either be equal to BAT,

or less than BAT since new sources can

more efficiently design their facilities to

comply with zero discharge. Costs for

new sources in the Gulf generating

treatment, workover and completion

fluids to meet zero discharge would be

approximately $520,000 per year which

is negligible in relation to annual

production revenue from Gulf coastal

operators.

For Cook Inlet, costs to meet Option

2 requirements for treatment, workover

and completion fluids are included in

the cost analysis for produced water

because current practice there is

commingling of these wastestreams (See

Section VI.E.). While EPA does not

anticipate any new sources to be

constructed in Cook Inlet, and therefore

has not attributed any costs to NSPS, the

NSPS would not cause a significant

barrier to entry. These impacts are only

a small incremental increase over the

impacts resulting from the controls on

produced water and drilling fluids and

cuttings. Finally the non-water quality

environmental impacts of this Option 2

are believed to be acceptable, because

like their volumes, they are relatively

small (See Section VIII of this preamble)

as discussed below.

Option 2 would result in the removal

of 3.9 million pounds of conventional,

toxic and non-conventional pollutants

annually (a total of 2140 in toxic pound

equivalents). However the amount of

toxic priority pollutants removed is

approximately 0.02 percent of this total.

The annual compliance costs of $1.1

million (for BAT and NSPS combined)

to remove 800 pounds of priority toxic

pollutants indicates that this option is

not cost effective. (See also EPA’s cost

effectiveness analyses entitled Cost

Effectiveness Analysis of Effluent

Limitations Guidelines and Standards

for the Coastal Oil and Gas Industry

found in the rulemaking record for this

proposal).

EPA is soliciting comments on

whether the volumes of treatment,

workover and completion fluids

removed by these options are

deminimus, and on the applicability,

achievability and practicality of both

Options 1 and 2.

b. PSES and PSNS.

Pretreatment standards for treatment

workover and completion fluids are

being proposed equal to zero discharge.

This is because their chemical

composition, like produced water, tends

to be high in total dissolved solids

which may interfere with POTW

operations. EPA did not have sufficient

data, however, to conduct a passthrough analysis for the pollutants

contained in this wastestream. Both

interference and pass-through are

discussed further in the Coastal

Technical Development Document. EPA

solicits comments on these issues. Zero

discharge for NSPS would not pose

barrier to entry for the same reason as

discussed under NSPS for this

wastestream.

EPA solicits comments on both the

occurrence of treatment, workover and

completion fluid discharges into

POTW’s and the appropriateness of

pretreatment standards requiring zero

discharge for this wastestream.

F. Domestic Wastes

Domestic wastes result from

laundries, galleys, showers, etc.

Detergents are often part of this

wastestream. Waste flows may vary

from zero for intermittently manned

facilities to several thousand gallons per

day for large facilities.

The conventional pollutant of concern

in domestic waste is floating solids. The

BPT limitations for deck drainage are no

discharge of floating solids. To comply

with this limit, domestic waste is

ground up so as not to cause floating

solids on discharge. EPA is proposing to

limit floating solids as well for BCT and

NSPS. In addition, EPA is proposing to

prohibit discharges of foam for BAT and

NSPS. Foam is a nonconventional

pollutant and its limitation is intended

to control discharges that include

detergents.

EPA is also proposing to limit

discharges of garbage as included in

U.S. Coast Guard regulations at 33 CFR

Part 151. These Coast Guard regulations

implement Annex V of the Convention

to Prevent Pollution from Ships

(MARPOL) and the Act to Prevent

Pollution from Ships, 33, U.S.C. 1901 et

seq. (The definition of ‘‘garbage’’ is

included in 33 CFR 151.05).

The pollutant limitations described

above for domestic wastes are all

technologically available and

economically achievable and reflect the

BCT, BAT and NSPS levels of control.

Under the Coast Guard regulations,

discharges of garbage, including

plastics, from vessels and fixed and

floating platforms engaged in the

exploration, exploitation and associated

offshore processing of seabed mineral

resources are prohibited with one

exception. Victual waste (not including

plastics) may be discharged from fixed
9460 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

or floating platforms located beyond 12

nautical miles from nearest land, if such

waste is passed through a screen with

openings no greater than 25 millimeters

(approximately one inch) in diameter.

Because vessels and fixed and floating

platforms must comply with these

limits, EPA believes that all coastal

facilities are able to comply with this

limit. While not all coastal facilities are

located on platforms, compliance with a

no garbage standard should be as

achievable, if not more so for shallow

water or land based facilities that have

access to garbage collection services.

Further, the final drilling permit

promulgated by Region VI for coastal

Texas and Louisiana incorporates these

Coast Guard regulations.

Since these BCT, BAT and NSPS

limitations for domestic waste are

already in either existing NPDES

permits or Coast Guard regulations,

these limitations will not result in any

additional compliance cost, and thus

these limits are economically

achievable. Also, these limits and

standards will have no additional nonwater quality environmental impacts.

There are no incremental costs

associated with the BCT limitations;

therefore, it is considered to pass the

two part BCT cost reasonableness test.

No discharge of visible foam is

required by Region X’s NPDES permit

for Cook Inlet drilling. No discharge of

floating solids is included in the Region

X’s BPT Cook Inlet general permit, the

Region X’s drilling permit and Region

IV’s general permit for coastal operators.

Pretreatment standards are not being

developed for domestic wastes because

they are compatible with POTWs.

G. Sanitary Wastes

Sanitary wastes from coastal oil and

gas facilities are comprised of human

body wastes from toilets and urinals.

The volume of these wastes vary widely

with time, occupancy, and site

characteristics. A larger facility, such as

an offshore platform, typically

discharges about 35 gallons of sanitary

waste daily. Sanitary discharges from

coastal facilities would be expected to

be less than this value since the

manning levels at most coastal facilities

is less than that at offshore locations.

Existing BPT limitations for facilities

continuously manned by 10 or more

people requires sanitary effluent to have

a minimum residual chlorine content of

1 mg/l, with the chlorine concentration

to remain as close to this level as

possible. Facilities intermittently

manned or continuously manned by

fewer than 10 people must comply with

a BPT prohibition on the discharge of

floating solids. EPA’s Regions VI and IV

NPDES general permits for coastal

facilities also impose limits on the

discharge of TSS, fecal coliform count,

BOD and floating solids. EPA’s Region

X general NPDES permit for Cook Inlet

also requires limitations for these same

parameters in addition to requirements

for foam and free oil.

EPA considered zero discharge of

sanitary wastes based on off-site

disposal to municipal treatment

facilities or injection with other oil and

gas wastes. Off-site disposal would

require pump out operations, that while

available to certain land facilities, are

not available to remote or water-based

operations. Because sanitary wastes are

not exclusively associated with oil and

gas operations, which are routinely

injected in Class II wells, zero discharge

based on Class II injection was not

considered for sanitary wastes. EPA

solicits comments on the selected

option for sanitary wastes regarding the

pollutant regulated, the limitation itself,

and other possible disposal options,

including marine sanitation devices that

are designed to prevent discharge (Type

III, 33 CFR 159.3(s)).

EPA is proposing to limit sanitary

waste discharges for BCT and NSPS

equal to BPT limitations. Sanitary waste

effluents from facilities continuously

manned by ten (10) or more persons

must contain a minimum residual

chlorine content of 1 mg/l, with the

chlorine level maintained as close to

this concentration as possible. Coastal

facilities continuously manned by nine

or fewer persons or only intermittently

manned by any number of persons must

comply with a prohibition on the

discharge of floating solids.

Since there are no increased control

requirements beyond those already

required by BPT effluent guidelines,

there are no incremental compliance

costs or non-water quality

environmental impacts associated with

BCT and NSPS limitations for sanitary

wastes. Since these limitations are equal

to BPT, they are available and

economically achievable. In addition,

the BCT limitation is also considered to

be cost reasonable under the BCT cost

test. Since the POTW test result and the

industry cost-effectiveness test results

are both zero (and therefore pass their

respective tests), the limitation is cost

reasonable.

EPA is not establishing BAT effluent

limitations for the sanitary waste stream

because no toxic or nonconventional

pollutants of concern have been

identified in these wastes.

Pretreatment standards are not being

developed for sanitary wastes because

they are compatible with POTWs.

VII. Economic Analysis

A. Introduction

EPA’s economic impact assessment is

presented in the Economic Impact

Analysis of Proposed Effluent

Limitations and Guidelines, and

Standards for the Coastal Oil and Gas

Industry (hereinafter, ‘‘EIA’’). This

report details the investment and

annualized costs of compliance with the

rule for the industry as a whole and the

impacts of the compliance costs on

affected wells, platforms, and operators

in the coastal oil and gas industry, both

existing and future. The report also

estimates the economic effect of

compliance costs on Federal and State

revenues, balance of trade

considerations, and inflation.

EPA also has conducted an analysis of

the cost-effectiveness of alternative

treatment options. The results of the

cost-effectiveness analysis are expressed

in terms of the incremental costs per

pound-equivalent removed. Poundequivalents account for the differences

in toxicity among the pollutants

removed. Total pound-equivalents are

derived by taking the number of pounds

of a pollutant removed and multiplying

this number by a toxic weighting factor.

The toxic weighting factor is derived

using ambient water quality criteria and

toxicity values. The toxic weighting

factors are then standardized by relating

them to a particular pollutant, in this

case copper.

Cost-effectiveness is calculated as the

ratio of incremental annualized costs of

an option to the incremental poundequivalents removed by that option.

This analysis, Cost-Effectiveness

Analysis of Effluent Limitations

Guidelines and Standards for the

Coastal Oil and Gas Industry

(hereinafter, the ‘‘CE Report’’), is

included in the record of this

rulemaking. Since the discharges are

primarily to a marine or brackish

environment, salt-water toxic weighting

factors (which typically are lower than

freshwater toxic weighting factors, thus

they generate lower pound-equivalents

overall) were used wherever they were

available.

Cost-effectiveness is a measure of

costs and relative economic efficiency of

the technology options being considered

to remove toxic pollutants. EPA

includes direct compliance costs, such

as capital expenditures, operations and

maintenance costs and in some cases

monitoring costs (i.e., direct compliance

costs), when estimating costeffectiveness. EPA has not included in

previous effluent guidelines and

standards costs associated with the

economic impact of the technology
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9461

2Net present value is the total stream of

production revenues minus costs over a period of

years discounted back to present value, under the

assumption that a future dollar is worth less than

a dollar now.

options in the costs used in the costeffectiveness analysis. Consistent with

this, for this effluent guidelines, EPA

has included capital expenditures and

operation and maintenance, but not the

cost of the lost oil/gas production in its

analysis of the incremental costeffectiveness of different technology

options. EPA does consider the lost

production as an economic impact on

this industry, and has included lost

production in its economic impact

analysis. During the interagency review

a question was raised whether EPA

should treat the lost oil/gas production

as a compliance cost to the facility. EPA

solicits comments on: (1) Whether the

possibly permanent loss in oil/gas

production associated with premature

closing of these wells may be different

from lower production of manufacturing

goods that occurs in any production

period as a result of higher production

costs, and (2) whether or not the lost

production of oil/gas should be

considered when determining the costeffectiveness on the technology options

for this industry.

B. Economic Methodology

The EIA provides the results of a

number of measures of economic impact

resulting from the proposed Coastal

Guidelines. These measures include

production losses (measured in terms of

total lifetime production lost, losses in

net present value (NPV) 2 of production,

and years of production lost), impacts

on federal and state revenues; impacts

on firms; impacts on employment;

impacts on inflation and balance of

trade; impacts on small businesses; and

impacts on new sources in terms of

barriers to entry. All impacts measured

in this EIA do not take into account the

requirements of the EPA Region VI

General Permits for the Coastal Oil and

Gas Industry covering disposal of

produced water.

These impacts are also based on the

assumption that oil prices will remain,

in real terms, approximately $18 per

barrel over the timeframe of the

analysis. This assumption is

substantiated, at least for this decade, by

recent industry forecasts. Note that if

the price of oil changes significantly,

impacts could also change.

1. Gulf of Mexico

EPA used the 1993 Coastal Oil and

Gas Questionnaire authorized under

section 308 of the CWA to obtain the

information necessary to model impacts

at wells determined to be currently

discharging and which were determined

to be continuing to discharge at least

through the third quarter of 1996.

Incremental compliance costs specific to

these wells or the produced water

separation and treatment facilities

associated with these wells (prorated on

a cost per barrel basis to make them

well-specific) were used to derive the

incremental costs to the affected wells.

By Gulf of Mexico, the EIA does not

generally include Gulf coastal facilities

in Alabama and Florida, since coastal

operators in these states are already

required to meet zero discharge, and

thus, these facilities would not incur

additional costs from this rule.

A financial model showing cash flow

over a maximum 30-year time frame (or

less if a well’s flow becomes negative

before 30 years) was developed and

adapted to each well using well-specific

data in the Questionnaire. Costs

included in the models include those

associated with current production costs

and revenues, which were extrapolated

over the lifetime of the project to

establish baseline lifetime production.

Other baseline summary statistics

included years of economic lifetime,

corporate cost per barrel of oil

equivalent (BOE), and net present value

of lifetime production. Then, capital

and annual operating and maintenance

(O&M) costs associated with various

regulatory options were added to the

baseline costs. The model recalculates

the economic lifetime of the wells,

annualizes the regulatory costs over the

new project lifetime, and recalculates

production and financial summary

statistics. Well impacts were evaluated

by determining the change from the

baseline values caused by the increased

regulatory costs. Production losses are

measured as reductions in hydrocarbon

extraction resulting from immediate

closure of existing wells and curtailed

lifetimes. These were based on the

decrease in production and decrease in

net present values for the wells induced

by the regulatory costs. That is, if a well

became unprofitable with the additional

costs, it was assumed to shut in, either

in the first year or earlier than it might

have under baseline assumptions.

To provide more accuracy in

estimating the total annual costs to the

Gulf of Mexico (GOM) coastal oil and

gas industry, these costs were derived

using state permit data on discharging

facilities and compliance cost estimates

developed on a per-facility basis. Thus

costs were not based on extrapolations

from survey data. These costs are pretax (although the financial models

account for impacts based on the

appropriate post-tax costs). EPA reemphasizes that this analysis assumes

that the Region VI permit for produced

water is not part of the baseline

scenario.

EPA also analyzed secondary impacts

of the regulation. These include:

revenue losses to the federal

government due to tax shields on

expenditures and loss of taxable

revenues, revenue losses to State

governments through lower severance

tax payments and royalties, changes in

the balance of trade and inflation,

employment losses (both primary and

secondary) based on production losses

and firm failures, and employment gains

(involved with manufacturing,

installing, and operating pollution

control equipment). Impacts on new

sources also are investigated and a

regulatory flexibility analysis is

performed.

2. Cook Inlet

The same type of financial model

used in the Gulf of Mexico portion of

the analysis was adapted to model 14

platforms (one currently shut in but

with potential for future production) in

the Cook Inlet. The same types of

impacts from a variety of regulatory

options for this region also were

estimated. One difference between the

Cook Inlet model and the Gulf model is

that the Cook Inlet model operates at the

platform level instead of the well level.

Impacts are evaluated for platforms,

whose production rates change with the

addition of new and recompleted wells.

C. Summary of Costs and Economic

Impacts

1. Overview of Economic Analysis

The economic analysis has five major

components: (1) An estimate of the

number of existing wells (Gulf of

Mexico) and platforms (Cook Inlet) and

projected wells/platforms that incur

costs under this rule; (2) an estimate of

the annual aggregate (pre-tax) cost of

complying with the regulation using

capital and O&M costs per Cook Inlet

platform or Gulf of Mexico treatment

facility as estimated in the Development

Document; (3) use of an economic

model to evaluate per-well/platform

impacts on production and economic

life; (4) an evaluation of impacts on

firms, future oil and gas production,

Federal and State revenues, balance of

trade, employment and other secondary

effects; and (5) the performance of a

regulatory flexibility analysis as

required under the Regulatory

Flexibility Act to determine whether

impacts on small firms are

disproportionate to those on large firms.
9462 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

The base year for the economic

analysis is 1992, so all costs are reported

in 1992 dollars. This is the year for

which data were gathered in the 1993

Coastal Oil and Gas Questionnaire and

was the most recent year for which a

complete set of cost, revenue, and

production data were available. Any

costs not originally in 1992 dollars were

inflated or deflated using the

Engineering News Record Construction

Cost Index, unless otherwise noted in

the EIA (see EIA for details).

The industry profile used in this

analysis is presented in Section IV. EPA

estimates that there are 4,675 existing

wells in the Gulf of Mexico Coastal

Region, of which 1,588 are estimated to

still be discharging produced water in

1996, according to estimates based on

Questionnaire 308 survey results. By

Gulf of Mexico, EPA has not included

Alabama or Florida since these facilities

are currently meeting zero discharge. As

noted above, this costing approach is

conservative because independent of

this rule, an additional 28 production

facilities (with an estimated 213 wells)

in coastal Louisiana will be required by

Louisiana state water quality standards

to achieve zero discharge by January

1997. Six new production facilities are

expected to be built each year in the

Gulf region. The costs for these new

projects are assigned as NSPS

compliance costs. In Cook Inlet, no new

facilities are anticipated, thus no NSPS

costs are calculated for purposes of

estimating the total costs of the rule.

EPA has, however, analyzed whether

the NSPS requirements for Cook Inlet

would create a barrier to entry for any

new sources that might begin to operate

in Cook Inlet.

EPA examined the effect of BPT, BCT,

BAT, and NSPS regulatory options. BPT

options have no costs or impacts and are

discussed no further here. BCT options

were examined using BCT cost tests (see

Section VI). BAT and NSPS economic

impacts are discussed in this section.

The following wastestreams are

regulated by this rule: produced water;

drilling wastes; well treatment,

workover, and completion fluids;

produced sand; deck drainage; sanitary

wastes; and domestic wastes. For

sanitary and domestic wastes, the BAT

and NSPS options proposed are current

permit conditions, thus no costs or

impacts are incurred as a result of BAT

or NSPS requirements for these

wastestreams. For deck drainage, the

limits are based on BPT, thus costs and

impacts of BAT or NSPS requirements

are zero. For produced sand, current

practice is zero discharge, and zero

discharge is the only option considered

for BPT, BAT or NSPS. Thus, no costs

or impacts are expected to result from

BAT or NSPS requirements for

produced sand. Therefore, the

remainder of this section discusses the

costs and impacts of BAT and NSPS

options only for produced water;

drilling waste; and treatment, workover,

and completion fluids.

In all, there are 10 BAT regulatory

options: 5 for produced water, 3 for

drilling wastes, and 2 for treatment,

workover, and completion fluids. These

options are described in Section VI. The

economic impacts from these options

are assessed individually in this

Section. Selected NSPS options are also

discussed in these sections.

2. Total Costs and Impacts of the

Regulations

This section presents the costs and

impacts of the selected BAT and NSPS

regulatory options. The total annual

costs of the BAT and NSPS regulatory

alternatives are presented in Table 6.

Note that the costs and impacts of this

rule would be substantially reduced if

the effects of the recently finalized EPA

Region VI General Permit were to be

incorporated in this rule. The preferred

BAT regulatory option for produced

water is Option 4, zero discharge

everywhere except in Cook Inlet where

discharges are allowed provided oil and

grease limitations, based on improved

gas flotations, are met.

TABLE 6.—TOTAL COSTS OF BAT AND NSPS OPTIONS (1992$)

Annual compliance costs ($ million/yr)

Wastestream 1 BAT NSPS

Produced water ................................................................................................................................ 30.86 4.48

Co-proposal

Opt 1 Opt 2 Opt 3 2 0

Drilling fluids and cuttings 0 1.4 3.89

Co-proposal Co-proposal

Opt 1 Opt 2 Opt 1 Opt 2

Treatment, workover, and completion fluids .................................................................................... 0 0.61 0 0.52

Total .......................................................................................................................................... 30.86–35.36 4.48–5.00

1EPA selected no-cost options for all other wastestreams.

2 No new sources expected in Cook Inlet.

The three options considered for

drilling fluids and cuttings BAT and

NSPS contain zero discharge for all

areas, except two of the BAT options

contain allowable discharges for Cook

Inlet. One of these options which would

allow discharges meeting a more

stringent toxicity limitation if selected

for the final rule, would require an

additional notice for public comment

since the specific toxicity limitation has

not been determined at this time. The

three options are: Option 1—zero

discharge for all areas except Cook Inlet

where discharge limitations require

toxicity of no less than 30,000 ppm

(SPP), no discharge of free oil and diesel

oil and no more than 1 mg/l mercury

and 3 mg/l cadmium in the stock barite,

Option 2—zero discharge for all areas

except for Cook Inlet where discharge

limitations would be the same as Option

1, except toxicity would be set to meet

a limitation between 100,000 pm (SPP)

and 1 million ppm (SPP), and Option

3—zero discharge for all areas. EPA is

co-proposing two options for BAT and

NSPS for treatment, workover and

completion fluids. Option 1 would

require no discharge of free oil and
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9463

3The industry will not experience the entire

impact of these costs because depreciation

allowances and increased costs of production

stemming from these compliance costs will serve to

reduce taxable income. Thus a portion of these

costs will be borne by federal and state governments

rather than industry or individual firm owners. This

portion is known as industry’s ‘‘tax shield.’’ This

impact to governments is, however, noted in the

analyses discussed below.

4The losses of $160.4 million included costs of

technology and resulting production losses.

prohibit discharges to freshwaters of

Texas and Louisiana. This option

reflects current practice. Option 2

would require the same limitations as

the preferred option for produced water.

This option would require for BAT that,

discharges of treatment, workover and

completion fluids would be prohibited

in all coastal areas except Cook Inlet. In

Cook Inlet, these discharges would be

required to meet a daily maximum oil

and grease limitation of 42 mg/l and a

30 day average of 29 mg/l. Option 2

would require zero discharged of these

fluids everywhere for NSPS.

The total cost of compliance with

these selected BAT options is $30.9

million to $35.4 million per year in

1992$’s (or $33.5 million to $38.4

million in 1994$’s). Additionally,

compliance with the BAT options

would result in up to approximately

$9.5 million in lost oil and gas revenues,

taxes and royalties annually.3

NSPS requirements for produced

water is zero discharge (only the Gulf is

expected to have new sources). The

options being co-proposed for NSPS for

drilling fluids and cuttings and

treatment, workover and completion

fluids are the same as those considered

for BAT. Total compliance cost of NSPS

for this proposal ranges from $4.48 to

approximately $5 million annually in

1992 $’s (or $4.9 to $5.4 million

annually in 1994 $’s). Additionally,

compliance with the selected NSPS

options could also result in roughly $1

to 2 million in lost oil and gas revenues,

royalties and taxes annually. Costs of

NSPS for produced water are associated

only with six new source production

facilities per year projected in the Gulf

region. No new sources are projected in

Cook Inlet. For the six new production

facilities constructed per year in the

Gulf, costs of the produced water NSPS

are estimated to be approximately $4.48

million per year or $38.4 million

(present value) over a 15-year time

frame.

Costs of NSPS for well treatment,

workover and completion fluids are

based on EPA projections that 45 new

source wells would be discharging these

fluids (without this rule) in the Gulf

region. No new sources are projected in

Cook Inlet. For the 45 new source wells

in the Gulf region costs of the NSPS

options for well treatment, workover

and completion fluids are estimated to

range from $0.00 to approximately $0.52

million per year or $0.00 to $4.4 million

(present value) over a 15-year time

frame.

Because current practice for control of

drilling fluids and drill cuttings in the

Gulf region is zero discharge and no

new sources are projected in Cook Inlet,

no additional costs will be incurred due

to NSPS for drilling fluids and drill

cuttings.

Total compliance cost of all BAT and

NSPS requirements ranges from $35.34

million to $40.36 million per year in

1992 $’s (or $38.3 million to $43.8

million annually in 1994 $’s). These

compliance costs will also result in up

to $11.5 million in lost oil and gas

revenues, royalties and taxes annually.

Note that these costs are a small

percentage of coastal revenues and

operating costs (the direct costs of

operating the business, i.e., not

including general and administrative

costs, depletion, depreciation, taxes,

interest, etc.). Total revenues stemming

from coastal operations among coastal

firms (Texas, Louisiana, and Cook Inlet,

Alaska, only) are estimated to be $6.1

billion per year. Thus the total annual

cost of the proposed Coastal Guidelines

is estimated to be at most 0.7 percent of

annual coastal revenues. The total

coastal operating costs among coastal

firms is estimated to be $1.2 billion per

year, thus annual compliance costs of

this proposed rule are estimated to be

up to 3.3 percent of total annual

operating costs.

BAT production losses under the

selected options are expected to total at

most 40.2 million barrels of oil

equivalent (BOE) over the lifetime of the

wells and platforms as a result of the

regulatory options (average

postcompliance lifetime is 10 years in

both the Gulf and Cook Inlet). In Cook

Inlet, the production loss over the

expected productive lifetime of the

platforms is expected to be up to 12.4

million total BOE, which is 3.1 percent

of the estimated lifetime production for

the region. In the Gulf, the lifetime

production loss is expected to be up to

27.9 million total BOE, which is 0.9

percent of a high estimate of lifetime

production and 1.7 percent of a low

estimate of lifetime production in the

Gulf. For the two regions combined, the

maximum 40.2 million BOE loss (or

17.9 million BOE in present value) in

production is 1.1 percent to 2.0 percent

of total lifetime production. These

losses are associated with declines in

the net present value of producer

income totalling up to $144.5 million in

the Gulf and $15.9 million in Cook Inlet

for a total of $160.4 million or 0.7 to 1.5

percent of total net present value of

baseline producer income in the two

regions.4 These losses result from both

immediate shut in of wells or platforms

and/or shortened economic lifetimes. A

total of up to 111 Gulf wells (2.4 percent

of all current coastal Gulf wells) and no

Cook Inlet platforms are considered

likely to shut in at once under the

proposed options. These shut-in wells

tend to be relatively low-producing or

marginal wells as can be seen from the

relatively lower percentage of

production affected as compared to a

higher percentage of wells.

A maximum of 12 firms owning and/

or operating Gulf Coastal wells might

possibly fail as a result of the proposed

regulatory options. Data were not

available to rule out the possibility of

firm failure, so they were counted as

potential firm failures, thus the actual

number of firm failures could be as few

as none. No failures are predicted for

operators in Cook Inlet. It is estimated

that the majority (72 percent) of firms in

the Gulf Coastal region by 1996 will not

discharge produced water. Thus, most

firms will incur no compliance costs.

The Gulf Coastal firms, therefore, are

potentially expected to face average

(median) declines in equity or working

capital of 0 percent. Discharging firms

are potentially expected to face average

(median) declines in equity and working

capital of 0.37 percent and 2.63 percent,

respectively.

The options potentially could result

in a present value loss of up to $91

million in federal and state income tax

revenues over an average of 10 years, or

up to $13.6 million, on average,

annually (primarily federal taxes). This

loss is only 11 percent of income taxes

from discharging wells and platforms

alone. Losses to state revenues due to a

potential loss of severance taxes total

$10.8 million over 10 years, or $1.6

million, on average, annually. This loss

is only 3.8 percent of severance taxes

from discharging wells and platforms

alone. The states could also potentially

lose royalties totaling at most, an

estimated present value of $39.4 million

over 10 years, or $5.9 million, on

average, annually, which is only 5.8

percent of royalties collected from

discharging wells and platforms alone.

These effects are negligible compared to

federal and state revenues and royalties

collected.

The proposed rule is not expected to

affect energy prices, international trade,

or inflation, and would have a minimal

impact on national-level employment.

Primary employment losses would be
9464 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

5Total losses calculated independently for

produced water and drilling waste will not add

exactly to the number cited above for combined

losses because the independent estimates double

count a very small portion of lost production in

Alaska (about 1.3 percent of production).

expected to be 181 full-time equivalents

(FTEs), which is 3.1 percent of total Gulf

and Cook Inlet employment (minus

baseline employment losses). Primary

and secondary losses are expected to

total 518 FTEs. Net employment losses

(including secondary effects and

accounting for employment gains) are

expected to be 121 FTEs. Additionally,

an estimated 1,561 FTEs would be lost

in the Gulf, on average, five years sooner

(in 10 years rather than in 15 years)

because of declines in wells’ productive

lifetimes. However, because these

impacts are not felt, on average, for 10

years and because ample time is

available for industry to adjust to

declines in wells’ productive lives

through natural job attrition, these

impacts are not considered major. This

loss is equivalent to declines in total

Gulf coastal employment averaging 3

percent per year over a 10-year period

under the regulation, compared to

declines averaging 2 percent a year over

a 15-year period without the regulation

or at most 337 FTEs on an equivalent

first year loss basis. Table 7 summarizes

the impacts discussed above. In Cook

Inlet, platforms shut in, on average, 1

year earlier (in 10 years instead of 11

years). This impact is considered minor

because ample time is still available for

workers to find alternative employment.

TABLE 7.—SUMMARY OF ECONOMIC IMPACTS TO GULF OF MEXICO AND COOK INLET REGIONS FROM THE SELECTED BAT

OPTIONS

Impact 1

Option

No. 4

produced

water

Drilling waste TWC

Total impacts 2

OPT 1 OPT 2 OPT 3 OPT 1 OPT 2

Number of wells or platforms shut in:

Wells ........................................................ 111 0 0 0 0 0 111 wells.

Platforms ................................................. 0 0 0 0 0 0 0 platforms.

Present value of lost production (million

BOE).

15.2 0 2.7 5.4 Negl. Negl. 15.2 to 17.9.

Total production lost (million BOE) ................ 32.4 0 3.6 7.8 Negl. Negl. 32.4 to 40.2.

Present value of producer income lost ($000) $153,209 0 $263 $6,089 Negl. Negl. $153,209 to $160,409.

Present value of federal taxes lost ($000) ..... $84,903 0 $2,586 $7,925 Negl. Negl. $84,903 to $90,950.

Present value of lost severance taxes ($000) $10,676 0 $133 $272 Negl. Negl. $10,676 to $10,815.

Present value of lost royalties to states ......... $34,255 0 $4,274 $9,394 Negl. ............... $34,255 to $39,375.

Total present value losses ($000) 3 ................ $283,043 0 $7,256 $23,680 Negl. Negl. $283,043 to $301,549.

1 Impacts from selected options for other wastestreams are expected to be negligible.

2 Impacts are not additive. Some double counting or undercounting of impacts occurs in the Cook Inlet analysis if produced water impacts are

added to drilling waste impacts. The total reflects the removal of double counting, with corrections made for undercounting. 3 Includes only dollar figures in columns. Losses comprise both compliance costs and value of lost production (net operating costs). Note that

these losses are not annual losses.

Based on the impacts predicted, EPA

finds the costs of the proposed BAT

limitations to be economically

achievable for the Coastal Oil and Gas

Industry.

NSPS requirements for produced

water in the Gulf (Cook Inlet NSPS

impacts are discussed below), for

drilling wastes, and for miscellaneous

wastes are equivalent to BAT

requirements. Costs for designing in

compliance equipment are typically less

than those for retrofitting the same

compliance equipment to existing

operations. Since new sources would

most likely face costs of compliance

equal to or less than existing operations,

NSPS for Cook Inlet produced water are

projected to pose no barriers to entry.

NSPS for produced water in Cook

Inlet are more stringent than BAT

requirements; however, declines in net

present value of production for existing

platforms under Coastal Guidelines BAT

limitations (2.4 percent) are only

negligibly less than net present value

declines modeled for new sources under

a zero discharge scenario (2.9 percent).

Further, the modeled NSPS platform

shows excellent internal rates of return

(a measure of profitability)

postcompliance, so NSPS should not

play a major role in a decision to

undertake the construction,

development, and operation of a

platform. Thus EPA finds that no

significant barriers to entry will be

created by NSPS for produced water in

Cook Inlet and that these standards

should be economically achievable,

given the minimal impact on net present

value and the internal rate of return.

D. Produced Water

1. BAT

As noted earlier, this analysis of

impacts associated with the effluent

guidelines for produced water does not

consider the effects of the Region VI

General Permit for produced water.

Because the Region VI General Permit

has been promulgated as zero discharge,

the costs and impacts of the limits on

produced water in the Gulf of Mexico

would be substantially less.

Total production losses associated

with the proposed option, Option #4 for

produced water (zero discharge except

for Cook Inlet), are expected to total 32.4

million BOE (or 15.2 million BOE in

present value) over the lifetime of the

wells and platforms subject to the rule. 5

In Cook Inlet, the production loss is

expected to be 4.6 million BOE, which

is 1.6 percent of the estimated lifetime

production for the region. In the Gulf,

the production loss is expected to be

27.9 million BOE. Lifetime production

in the Gulf is estimated to be 1,055 to

3,183 million BOE (693 to 13,910 BOE

in present value terms) (over a 30-year

time frame, based on a low and high

estimate of decline rate in the region).

Thus, this lost production is 0.9 to 1.7

percent of expected lifetime production

in the Gulf. For the two regions

combined, the lost production of 32.4

million BOE would result in a loss of

1.0 percent to 1.7 percent of total

lifetime production. These losses are

associated with declines in the net

present value of producer income

totalling $144.5 million in the Gulf and

$8.8 million in Cook Inlet for a total of

$153.3 million (total lifetime losses).

These losses result from both immediate

shut in of wells or platforms and
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9465

6NSPS models were run for Cook Inlet in the

Offshore EIA because EPA considered including

Cook Inlet in the offshore subcategory, but finally

included the operations in the Coastal subcategory.

The NSPS models constructed for the Offshore EIA

were used as the basis for modeling the existing

Cook Inlet platforms in the Coastal Guidelines EIA,

thus comparisons between NSPS platforms and

BAT platforms can be made.

shortened economic lifetimes. A total of

111 Gulf wells (2.4 percent of all current

coastal Gulf wells) and no Cook Inlet

platforms are considered likely to shut

in as a result of this rule. These shutin wells tend to be relatively lowproducing and marginal wells.

At most, 12 firms owning and/or

operating Gulf Coastal wells (2.8 percent

of the estimated 435 Gulf Coastal region

operators) might potentially fail as a

result of the selected BAT option (i.e.,

data are not available to rule out this

possibility, although the actual number

could be as small as none). No firm

failures are predicted for operators in

Cook Inlet. The ‘‘average’’ Gulf Coastal

firm does not discharge produced water

(there are a total of 435 firms and more

than 50 percent—actually 72 percent—

will not be discharging in coastal areas

by 1996). Thus, Gulf Coastal firms are

potentially expected to face average

(median) declines in equity or working

capital of 0 percent since the majority of

Gulf firms do not discharge and thus

will not incur compliance costs. Of the

122 discharging firms, average (median)

declines in equity or working capital of

0.37 percent or 2.63 percent are

expected to occur, respectively.

The selected option potentially could

result in a $84.9 million loss in federal

tax revenues over an average of 10 years,

or $12.6 million, on average, annually.

This loss is only 10 percent of income

taxes collected from discharging wells

and platforms alone. Losses to state

revenues due to a potential loss of

severance taxes total $10.7 million or

$1.6 million, on average, annually. This

loss is only 3.8 percent of severance

taxes from dischargers alone. State

royalties lost total $34.3 million, or $5.1

million, on average, annually. This loss

is only 5.1 percent of royalties from

dischargers alone. These effects are

negligible compared to federal and state

revenues and royalties collected.

The selected option is not expected to

affect energy prices, international trade,

or inflation, and will have a minimal

impact on national-level employment.

Primary employment losses are

expected to be 181 FTEs. Primary and

secondary losses are expected to total

518 FTEs. Net employment losses

(including secondary effects and

employment gains) are expected to be

128 FTEs. Table 8 summarizes the

impacts from the proposed produced

water option.

Based on the minimal impacts

predicted, EPA finds that the proposed

BAT option for produced water is

economically achievable for the Coastal

Oil and Gas Industry.

2. NSPS

This section discusses the barrier-toentry analysis for all regions but Cook

Inlet first, then NSPS relative to Cook

Inlet is discussed separately. Total

annual costs associated with NSPS

requirements for produced water in the

Gulf of Mexico (the only region where

NSPS projects are of concern) are $4.5

million per year. The selected NSPS

requirement is equivalent to BAT

requirements in this region. Because

NSPS is equivalent to BAT outside of

Cook Inlet region, and BAT has been

found to be economically achievable,

NSPS requirements for all but Cook

Inlet (which will be discussed

separately below) would not pose a

barrier to entry and are considered

economically achievable.

TABLE 8.—SUMMARY OF ECONOMIC

IMPACTS TO GULF OF MEXICO AND

COOK INLET REGIONS FROM PRODUCED WATER BAT OPTION NO. 4

[Zero discharge except Cook Inlet]

Impact Option No. 4

produced water

Number of wells or platforms shut in.111 wells.

0 platforms.

Present value of production loss (million BOE).15.2.

Total production lost (million BOE).32.4.

Net present value of producer income lost ($000).$153,209.

Present value of federal

taxes lost ($000).

$84,903.

Present value of lost severance taxes.$10,676.

Present value of lost royalties to states.$34,255.

Total present value losses

($000).

$283,043.

Employment effects ........... 128 FTEs lost.

Two NSPS economic models were run

for Cook Inlet in the EIA for the

Offshore Effluent Guidelines (EPA,

1993, Table 7–19; Table 7–21).6 These

models include a 24-slot gas/oil

platform and a 12-slot gas platform. The

gas/oil platform was estimated to incur

incremental compliance costs for

produced water disposal under a zero

discharge requirement of $1.8 million

annually (inflated to 1992 dollars). The

key impacts affecting whether a new

project would be undertaken (which

would lead to conclusions about

barriers to entry) include impacts on net

present value (NPV) and impacts on the

internal rate of return (IRR). The gas/oil

24 is projected to face declines in NPV

of 2.9 percent from baseline under a

zero discharge requirement for

produced water. IRR drops 5.1 percent,

however, this drop is estimated to be

from 39 percent in the baseline to 37

percent in the zero-discharge scenario.

These impacts are not likely to affect the

decision to undertake a project in Cook

Inlet (given production levels similar to

existing Cook Inlet platforms).

Additionally, the impact on NPV from

the zero-discharge requirement is not

substantially different from the impacts

on NPV from the proposed BAT option

under the Coastal Guidelines at existing

Cook Inlet platforms. The decline in

NPV projected for the Coastal rule BAT

option is 2.4 percent. Thus, existing

platforms and new platforms will face

similar impacts on NPV even though the

NSPS requirement is more

environmentally stringent than the BAT

requirement.

Costs and impacts associated with the

Cook Inlet 12-slot platform are much

less than those associated with the 24-

slot platform or with existing platforms

under the proposed BAT option for

produced water under the Coastal

Guidelines (see EPA, 1993, Table 7–21

and Section D.1 of this preamble).

Based on the analyses performed for

the Offshore Guidelines (which

continue to be relevant analyses for the

Coastal Guidelines), EPA concludes that

impacts on new sources in Cook Inlet

are minimal and that NSPS

requirements should pose no significant

barriers to entry for two reasons: (1)

declines in returns (measured as NPV

and IRR) most likely would not affect

the decision to undertake a new project

since operations would still be quite

profitable and (2) the level of impacts on

new sources from NSPS requirements

are not substantially greater than those

on existing sources from BAT

requirements.

E. Drilling Fluids and Drill Cuttings

1. BAT

As noted above, current practice in

the Gulf of Mexico region is zero

discharge of drilling fluids and drill

cuttings; and therefore, this proposed

rule would result in no additional costs

to Gulf operators. The three options

being co-proposed affect Cook Inlet

operations. Option 1 would result in no

economic impacts. Option 2 would

cause a total 3.6 million BOE loss in

production over 15 years. This

represents a 1.2 percent reduction in the

estimated lifetime production for the
9466 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

existing platforms in Cook Inlet as result

of three wells not being drilled. The net

present value of this production loss

(reduction in producers’ net income) is

$263,000 or less than 0.1 percent of

baseline net present value. The average

well life decreases by 0.2 years as a

result of this option. Additionally,

Federal income tax receipts would

decline by $2.6 million, state income tax

receipts by $133,000 and royalties paid

to Alaska by $4.3 million.

Option 3 would cause a production

loss of 7.8 million BOE, which is equal

to a 2.5 percent decline in the lifetime

production in Cook Inlet. No platforms

are expected to close. Federal income

tax lost (over the life of the platforms)

is estimated to decline $7.9 million (3.4

percent of baseline), or $1.3 million, on

average, per year. No firm failures are

predicted for operators in Cook Inlet.

Total state severance tax revenues are

predicted to decline by $0.27 million

(0.5 percent of baseline), or $0.04

million, on average, annually. Option 3

are not expected to affect energy prices,

international trade, or inflation, and

would have a minimal impact on

national-level employment.

Employment losses are not expected.

Employment gains (including secondary

effects) are expected to be

approximately 7 FTEs, under either

Option 2 or Option 3.

Based on the impacts predicted, EPA

finds that the costs of all three options

for drilling wastes are economically

achievable for the Coastal Oil and Gas

Industry. Table 9 summarizes the

impacts from the proposed BAT options

for drilling waste.

TABLE 9.—SUMMARY OF TOTAL ECONOMIC IMPACTS FROM DRILLING WASTE OPTION NO. 3

Impact

Option No. 3 drilling waste

Opt 1 Opt 2 Opt 3

Number of Wells or platforms shut in:

Wells ................................................................................................................................... 0 0 .......................... 0.

Platforms ............................................................................................................................ 0 0 .......................... 0.

Present value of total production lost (million BOE) ................................................................. 0 2.7 ....................... 5.4.

Total production lost (million BOE) ........................................................................................... 0 3.6 ....................... 7.8.

Net present value of producer income lost ($000) .................................................................... 0 $263 .................... $6,089.

Present value of federal taxes lost ($000) ................................................................................ 0 $2,586 ................. $7,925.

Present value of lost severance taxes ($000) ........................................................................... 0 $133 .................... 272.

Present value of lost royalties to states .................................................................................... 0 $4,274 ................. $9,394.

Total present value losses ($000) ............................................................................................. 0 $7,256 ................. $23,680.

Employment effects ................................................................................................................... 0 7 FTEs gained .... 7 FTEs gained.

2. NSPS

The same options are being

considered for NSPS as were for BAT.

Thus, both new platforms and existing

platforms face the same requirements.

Since costs for new operations to design

in compliance equipment should be as

expensive as or less expensive than

those for existing operations to retrofit

the same compliance equipment, no

significant barriers to entry are

predicted to exist. Furthermore, since

BAT was found to be economically

achievable, NSPS is considered

economically achievable.

F. Treatment, Workover, and

Completion Fluids

1. BAT

No costs are incurred for Option 1.

Costs of disposing of treatment,

workover, and completion fluids under

Option 2 are approximately $610,000

annually for all Gulf wells estimated to

discharge treatment, workover, and

completion fluids. A typical Gulf Coast

well produces an average of 36 barrels

of oil per day according to the 1993

Coastal Oil and Gas Questionnaire. At

$18 per barrel, total annual production

revenue at a typical well is estimated to

be $237,000. Treatment, workover, and

completion fluids disposal costs are

estimated to be 0.74 percent of annual

production revenues at a typical Gulf

Coastal well, and no major impacts are

expected as a result of either of the

selected option (refer to Table 6). For

this reason, EPA finds that the costs of

Option 2 for treatment, workover, and

completion fluids should be

economically achievable for the Coastal

Oil and Gas Industry.

2. NSPS

The options considered for NSPS for

treatment, workover, and completion

fluids are the same as those for BAT.

Because NSPS is equivalent to BAT in

the Gulf, new operations face the same

or lower costs as existing operations.

Thus, treatment, workover and

completion fluids disposal costs for

Option 2 will be 0.7 percent or less of

annual production revenues at a typical

Gulf coastal well. In Cook Inlet, there

are no costs for zero discharge of this

wastestream because this wastestream is

commingled with produced water, and

thus, the cost has already been

accounted for in costing zero discharge

for produced water. Option 2 NSPS

requirements will not pose a significant

barrier to entry. Furthermore, since BAT

in the Gulf and NSPS in Cook Inlet is

economically achievable, NSPS is

economically achievable.

G. Cost-Effectiveness Analysis

In addition to the foregoing analyses,

EPA has performed a cost-effectiveness

analysis for the selected options for

produced water; treatment, workover,

and completion fluids; and drilling

wastes. According to EPA’s standard

procedures for calculating costeffectiveness, all the options considered

for each waste stream have been ranked

in order of increasing poundsequivalent (PE) removed (see the

introduction to this section for a

discussion of pounds-equivalent, a

methodology for putting pollutants of

differing toxicity on a comparable

basis.) Cost-effectiveness is calculated as

the ratio of the incremental annual costs

to the incremental pounds-equivalent

removed under each option. So that

comparisons of the cost-effectiveness

among regulated industries can be

made, annual costs for all costeffectiveness analyses are reported in

1981 dollars.

In 1981 dollars, the incremental costeffectiveness for the selected options

are:

—$3/PE for produced water

—$0/PE for Option 1, $769/PE for

Option 2 and $292/PE for Option 3 for

drilling wastes

—$0/PE for Option 1 and $200/PE for

Option 2 for treatment, workover, and

completion fluids

H. Regulatory Flexibility

All of the firms expected to fail (0 to

12 firms) as a result of the proposed rule
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9467

are small entities (i.e., they employ

fewer than 500 employees), however,

nearly all the firms operating in the

Coastal region are small (approximately

372 out of an estimated 435 firms, or 86

percent are small firms). Thus 0 percent

to 3 percent of small firms could

potentially fail as a result of this rule.

The high end of this estimate is very

conservative because these firms might

not fail; however, but data were

unavailable to rule out the possibility.

Thus these firms were considered to

have the potential to fail as a result of

the proposed rule. Due to data

constraints, a cash flow analysis was not

undertaken, but potential effects on

working capital and equity were

analyzed. In general, the average small

firm that is currently discharging

produced water or other wastes will

experience a somewhat greater decline

in working capital or equity than that

for large firms. Among small

dischargers, the median change in

equity is 1.26 percent as compared with

0.02 percent for large firms, and the

change in working capital is 4.54

percent, versus 0.05 percent for large

firms. However, the typical small

discharging firm will not experience a

change in equity or working capital of

more than 5 percent. Additionally most

small firms are currently not

discharging any wastes, thus will

experience no change in equity or

working capital. When these

nondischarging firms are also

considered, the median small firm

operating in the coastal region will

experience no change in equity or

working capital. Thus EPA does not find

that impacts on small firms will be

disproportionately greater than those on

large firms.

VIII. Non Water Quality Environmental

Impacts

The elimination or reduction of one

form of pollution has the potential to

aggravate other environmental

problems. Under sections 304(b) and

306 of the CWA, EPA is required to

consider these non-water quality

environmental impacts (including

energy requirements) in developing

effluent limitations guidelines and

NSPS. In compliance with these

provisions, EPA has evaluated the effect

of these regulations on air pollution,

solid waste generation and management,

consumptive water use, and energy

consumption. Because the technology

basis for the limitation on drilling fluids

and drill cuttings may require

transporting the wastes to shore for

treatment and/or disposal, adequate

onshore disposal capacity for this waste

is critical in assessing the options.

Safety, and impacts of marine traffic on

coastal waterways, were other factors

also considered. EPA evaluated the nonwater quality environmental impacts on

a regional basis because the different

regions each have their own unique

considerations.

A. Drilling Fluids and Cuttings

The control technology basis for

compliance with the options considered

for the drilling fluids and drill cuttings

wastestreams is a combination of

product substitution, grinding followed

by injection, and/or transportation of

drilling wastes to shore for treatment

and/or disposal. The non-water quality

environmental impacts associated with

the treatment and control of these

wastes are summarized in Table 10.

These non-water quality environmental

impacts are those associated with

drilling fluids and cuttings disposal and

treatment alternatives only in Cook

Inlet. All other coastal areas are

currently achieving zero discharge of

these wastes and, thus the control

options cause no additional impacts.

Non-water quality environmental

impacts estimates are presented in more

detail in the Coastal Technical

Development Document.

TABLE 10.—NON-WATER QUALITY IMPACTS FOR DRILLING WASTE CONTROL OPTIONS

Options

Volume of

waste transported to onshore disposal 3

Volume of

ground and injected waste

(bbls)

Air emissions

(tons/yr)

Fuel requirements

(BOE) 2/year

Option 1: Zero for all except BPT for Cook Inlet 1 ........................................... 0 0 0 0

Option 2: Zero for all except for Cook Inlet with more stringent toxicity limit . 93,984 0 9 1,700

Option 3: Zero for all ........................................................................................ 422,780 130,066 12.5 2,300

1Option one represents current standards such that no additional barrels of wastes or resulting air emissions or fuel requirements are required.

2BOE (barrels of oil equivalents).

3The volume of barged waste does not include wastes that would be ground and injected. The air emissions and fuel requirements presented

in this table are a result of transporting these barged wastes and for grinding and injecting the rest.

1. Energy Requirements

Energy requirements for Options 2

and 3 were calculated by identifying

those activities necessary to support

onshore disposal of drilling wastes and

injection at the platform. The only

landfill available for disposal of drilling

wastes in Cook Inlet is privately owned

and operated. Access to this landfill is

limited to only the two operators that

own and operate it. The landfill, which

is located on the west side of Cook Inlet,

is only operated for four months in the

summer because of climate conditions

that are specific to Cook Inlet. Drilling

wastes are first transported by supply

boats from the platform to a temporary

storage facility on the east side of Cook

Inlet to be unloaded and temporarily

stored. Barges are used to transport

drilling wastes from the east to the west

side of Cook Inlet. Trucks are then used

to transport the muds and cuttings to

the landfill. For the other operators in

Cook Inlet, the technology basis for

Option 3 (zero discharge) is grinding

followed by injection at the platform.

For Option 2 (which includes a 100,000

ppm (SPP) to 1,000,000 ppm (SPP)

toxicity limitation that all operators

would not be able to meet), the

technology basis would be

transportation and disposal to the lower

contiguous United States for those

operators not having access to Alaska

landfills Option 2.

EPA used the volumes of drilling

waste requiring onshore disposal to

estimate the number of supply boat trips

necessary to haul the waste to shore.

Projections made regarding boat use

included types of boats used for waste

transport, the distance travelled by the

boats, allowances for maneuvering,

idling and loading operations at the drill

site, and import activities at the marine

transfer station. EPA estimated fuel

required to operate the cranes at the

drill site and import based on

projections of crane usage. EPA

determined crane usage by considering

the drilling waste volumes to be

handled and estimates of crane handling

capacity. EPA also used drilling waste
9468 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

volumes to determine the number of

truck trips required. The number of

truck trips, in conjunction with the

distance travelled between the marine

transfer station and the disposal site,

enabled an estimate of fuel usage. The

use of land-spreading equipment at the

disposal site was based on the drilling

waste volumes and the projected

capacity of the equipment. In evaluating

the zero discharge requirement, EPA

calculated for those operators that do

not have access to the landfill in Cook

Inlet, fuel requirements for grinding and

injection equipment. The equipment

evaluated included the pumps running

the cuttings grinding system (the ball

mills and conveyors) and the injection

pumps. The methodology used to

determine fuel consumption is further

discussed in the Coastal Technical

Development Document. Table 9

summarizes the incremental increase in

energy requirements for the drilling

fluids and drill cuttings options

considered for this rule.

2. Air Emissions

EPA estimated air emissions resulting

from the grinding and injection

equipment systems, or the operation of

boats, cranes, trucks and earth-moving

equipment necessary to either dispose

of drilling fluids and drill cuttings

onshore or to grind and inject these

wastes by using emission factors

relating the production of air pollutants

to time of equipment operation and

amount of fuel consumed. The

incremental increase in air emissions

associated with the control options

considered by EPA in this final

rulemaking are presented in Table 9.

In developing regulations to control

air pollution from OCS sources pursuant

to the 1990 Clean Air Act Amendments,

the EPA Office of Air Quality Planning

and Standards estimated the air

emissions associated with various stages

of oil/gas resource development

activities (‘‘Control Costs Associated

With Air Emission Regulations For OCS

Facilities,’’ Final Report September 30,

1991. Prepared by Mathtech, Inc. for

EPA). In this study, EPA estimated

levels of both controlled and

uncontrolled emissions from

exploration, development, and

production operations. Information from

this study was used to determine

emissions from coastal operations

independent of this rule. Nitrogen

oxides (NOX) emissions from

exploratory drilling activities were

estimated at 78 tons/operation. For

comparison, the zero discharge

requirement for all drilling activities in

the Cook Inlet projected over the next

seven years from scheduled

promulgation is estimated at

approximately 54 tons of NOX for each

well subject to the zero discharge

limitations.

3. Solid Waste Generation and

Management

The regulatory options considered for

this rule will not cause generation of

additional solids as a result of the

treatment technology. However, as

already discussed, spent drilling fluids

and drill cuttings may be disposed of

onshore to comply with these options.

There are currently no commercially

operating disposal sites in Cook Inlet

accepting drilling wastes. The only land

disposal facility accepting drilling

wastes from Cook Inlet operations is

privately owned and operated. The lack

of commercial disposal sites would

require operators that do not own a land

disposal facility to either transport the

drilling wastes to the nearest known

commercial disposal facility located in

Idaho or inject the drilling wastes into

underground formations.

Capacity estimates for the only

available disposal facility in Cook Inlet

show that this landfill has enough

storage capacity to accept the volume of

drilling fluids and cuttings (422,780

bbls over the next seven years following

promulgation of this rule) that would be

generated under Option 3 (zero

discharge) from the two operators that it

now serves. The volume of drilling

wastes generated by these two operators

under the zero discharge option

represents about 71 percent of the

excess available capacity at this landfill.

The other Cook Inlet operators would

not dispose of their drilling fluids and

cuttings by landfilling, but rather by

grinding and injection (See Section VI),

which does not require land disposal.

Under Option 2, the estimated volume

of drilling fluids and cuttings requiring

land disposal is estimated to be

approximately 17 percent of the total

wastes generated over the next seven

years following promulgation of this

rule (or 17 percent of 552,846 bbls

which is approximately to 94,000 bbls).

This is based on the estimate of 83

percent compliance with a toxicity

limitation between 100,000 ppm (SPP)

and 1,000,000 ppm (SPP). EPA

estimates that the two operators having

access to the Cook Inlet landfill will

send their portion of these wastes there

(amounting to approximately 72,000

bbls), and as shown above, there would

be sufficient landfill capacity to

accommodate this as well as the zero

discharge option. The other three

operators not having access to the Cook

Inlet landfill would most likely dispose

of their drilling fluids and cuttings for

this option (amounting to approximately

22,000 bbls) in a landfill available in

Idaho, rather than grind and inject them

(See Section VI), because this is less

expensive than installing grinding and

injection equipment for these smaller

volumes. Because of this small volume

of wastes, EPA assumed that there is

ample landfill capacity in the lower 48

states for disposal of 22,000 bbls of

wastes that would be generated over the

seven years following the scheduled

promulgation.

4. Consumptive Water Use

Since little or no additional water is

required above that of usual

consumption, no consumptive water

loss is expected as a result of this rule.

5. Safety

EPA investigated the possibility of an

increase in injuries and fatalities that

would occur as a result of hauling

additional volumes of drilling wastes to

shore. EPA acknowledges that safety

concerns always exist at oil and gas

facilities, regardless of whether

pollution control is required. EPA

believes that the appropriate response to

these concerns is adequate worker safety

training and procedures as is practiced

as part of the normal and proper

operation of oil and gas facilities.

6. Increased Vessel Traffic in Cook Inlet

EPA estimates that a total of 231 boat

trips would be required to comply with

a zero discharge requirement. This

estimate is for all drilling that will take

place in the next seven years after

expected promulgation of the rule. In

actuality, EPA determined, from drilling

schedules supplied by industry, that

drilling would only occur for seven

years after promulgation. Thus, these

231 boat trips equate to approximately

33 additional boat trips per year for

seven years. EPA does not expect this to

cause traffic problems in the Inlet. In

fact, it will serve to provide service

companies with additional work. EPA

has calculated expected job gains

associated with the manufacture,

installation and operation of

technologies required to comply with

this rulemaking.

However, job gains could also be

realized due to increased boat trips and

related work required of service

companies. These job gain estimates

have not been quantified.

B. Produced Water

In assessing the non-water quality

environmental impacts of the options

considered for control of produced

water, EPA projected the incremental

increase in energy requirements and air
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9469

emissions associated with the regulatory

options considered. These non-water

quality environmental impacts are

presented in Table 11.

TABLE 11.—NON-WATER QUALITY ENVIRONMENTAL IMPACTS FOR PRODUCED WATER

Option

Fuel requirements

(BOE/yr)

Total emissions (tons/

yr)

BAT NSPS1 BAT NSPS1

1. BPT All ................................................................................................................................. 0 0 0 0

2. Oil and Grease ..................................................................................................................... 28,595 1,712 258 17

3. Zero Discharge; Cook Inlet BPT 48/72 ................................................................................ 258,946 5,948 2,799 64

4. Zero Discharge; Cook Inlet Oil and Grease ........................................................................ 260,376 5,948 2,801 64

5. Zero Discharge All ............................................................................................................... 343,759 5,948 2,899 64

1 Impacts are associated only with new sources in the Gulf of Mexico. No new sources are expected in other coastal areas.

For small volume production facilities

in the Gulf, produced water would be

transported to commercial facilities for

injection to comply with the options

based on either gas flotation or injection

because it is less expensive for smaller

flows than installing injection or gas

flotation equipment on-site. Produced

water transportation (via barge or truck),

and vacuum pumps to unload produced

water at the commercial facilities are

sources included in fuel use and air

emissions calculations. For medium to

large volume facilities in the Gulf and

in Cook Inlet, either gas flotation or

injection would be the technology bases

to comply with the options. EPA

determined the fuel requirements and

air emissions for these technologies by

evaluating:

• Power requirements to operate feed

pumps and gas flotation devices

• Injection pumps and feed pumps

for injection and pretreatment

technology

Energy consumption for the different

options was determined based on the

produced water flowrates and the

associated power requirements for

operating treatment and injection

systems.

EPA calculated the air emissions for

each discharging facility by taking the

product of specific emission factors, the

usage in hours (that is, hours per year),

and the horsepower requirements. EPA

calculated total emissions for zero

discharge based on the use of

reciprocating natural gas fired engines

as the power source for the injection

pumps. According to industry, these

engines are commonly used in coastal

production facilities. Air emissions

increases calculated for the produced

water options include nitrogen oxides

(NOX), sulfur dioxide (SO2), and

hydrocarbons. See the Coastal Technical

Development Document for more detail

on the estimated compliance costs and

EPA’s calculation of pollutant removals

and non-water quality environmental

impacts.

The only increase in vessel waterway

traffic due to these options would be for

the small facilities that would be

required to barge their produced waters

to a commercial facility. This amounts

to approximately 50 facilities out of a

total of 216. Because vessels generally

service several facilities on any given

trip, EPA expects this increase to be

small enough that it will be absorbed

into current vessel operations.

Additionally, use of the coastal

waterways by the oil and gas industry

accounts for less than 10 percent of all

commercial traffic according to data

from the Minerals Management Service.

A slight increase in vessel traffic due to

this rule would have negligible effect on

the water traffic overall.

C. Treatment, Workover and Completion

Fluids

The non-water quality environmental

impacts associated with disposal of

treatment, workover and completion

fluids are the fuel requirements and air

emissions resulting from transportation

to commercial disposal where operators

choose this method to comply with the

rule. No incremental energy

requirements and air emissions have

been estimated for existing facilities that

treat and discharge or inject treatment,

workover and completion fluids onsite.

This is because the control options for

the facilities that treat and inject onsite

are based on commingling treatment,

workover and completion fluids with

the produced water and, therefore, nonwater quality environmental impacts

associated with this activity have

already been taken into account in

assessing the impacts of control options

for produced water.

Option 1, requiring BPT limits and

zero discharge to freshwaters in

Louisiana, would not cause additional

non-water quality impacts because it

reflects current practice (zero discharge

of these fluids is a requirement in the

Region VI general drilling permit).

Option 2, requiring limitations equal

to those for produced water, would

result in the consumption of

approximately 1000 and 300 additional

BOE per year, for BAT and NSPS

respectively, and the generation of 12

and 3 tons of additional emissions per

year for BAT and NSPS respectively.

IX. Executive Order 12866

Under Executive Order 12866, (58 FR

51735; October 4, 1993) the EPA 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 recommendation will be

documented in the public record for this

rulemaking.
9470 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

X. Executive Order 12875

Executive Order No. 12875 requires

Federal Agencies to consider the

impacts that unfunded mandates will

have on state, local, or tribal

governments. The coastal oil and gas

industry is not associated with tribal

governments, and the burden to state

and local regulatory authorities is

expected to be minimal, if not

decreased, by the implementation of

this rule.

The CWA, section 301 prohibits

discharges of pollutants unless

permitted under sections 402 or 404 of

the CWA. Effluent limitations

guidelines, new source performance

standards and pretreatment standards

are implemented through the National

Pollutant Discharge Elimination System

(NPDES) permits issued under section

402 of the CWA by EPA’s Regions or, if

delegated NPDES authority, the

delegated states. Generally, coastal oil

and gas facilities are permitted by EPA

Regions, or in the case of Alabama, by

the Alabama NPDES program, using

general permits which cover an entire

area specified in that permit. For

example, Region VI’s general permit for

coastal drilling operations covers all

coastal operations in Texas and

Louisiana, except for a few facilities

whose operations are noted in the

permit. Alabama currently requires zero

discharge in their permits for coastal oil

and gas operations.

These proposed requirements, when

promulgated, will be implemented via

the existing regulatory structure and no

additional burden is expected. In the

absence of effluent limitations

guidelines, establishing BAT, BCT,

NSPS, PSES and PSNS, permit

limitations are to be developed on as

case-by-case ‘‘Best Professional

Judgement’’ (BPJ) basis. In addition, all

NPDES permits must incorporate state

water quality standards. Once, these

Coastal Guidelines are in place, the

Regions will no longer be required to

expend both in-house and contractor

efforts in BPJ developments, and where

zero discharge is required, the Regions

and states will no longer be required to

determine permit limitations based on

water quality standards. Thus, these

guidelines will actually serve to reduce

the regulatory burden on the Regions

and states that permit existing sources

in the coastal oil and gas industry. As

it could take approximately $100,000 for

contractor support, and at least one inhouse FTE per general permit

development based on BPJ and water

quality requirements, this could result

in substantial savings. However,

issuance of NSPS creates a class of

facilities that is regulated as new

sources which may need to be permitted

by the regions and states. Because the

number of new sources is projected to

be very small and can be permitted by

general permits, we expect this to be a

minimal resource requirement.

Since the inception of the project in

1994, there have been periodic meetings

with the industry and several trade

associations, including the Louisiana

and Texas Independent Oil and Gas

Associations (TIOGA and LIOGA) and

American Petroleum Institute (API) to

discuss progress on the rulemaking. The

Agency also has met with the Natural

Resources Defense Council (NRDC) to

discuss progress on this rulemaking.

Because all of the facilities affected by

this proposal are direct dischargers, the

Agency did not conduct an outreach

survey of POTWs.

The Agency also held a public

meeting on July 19, 1994. The purpose

of the meeting was to present the project

status and discuss the technical options

under consideration for this proposal.

Representatives from industry trade

associations, individual industry

companies, state regulatory authorities

the U.S. Department of Energy and

Interior (Minerals Management Service)

and the Sierra Club Legal Defense Fund

attended.

The Agency will continue this process

of consulting with state, local, and other

affected parties after proposal in order

to further minimize the potential for

unfunded mandates that may result

from this rule.

XI. Paperwork Reduction Act

The proposed coastal oil and gas

effluent limitations guidelines and

standards contain no new information

collection activities, and therefore, no

information collection request will be

submitted to OMB for review in

compliance with the Paperwork

Reduction Act, 44 U.S.C. 3501 et seq.

XII. Environmental Benefits Analysis

A. Introduction

The Water Quality Benefit Analysis

(Benefit Analysis) evaluates the effect of

current discharges and the benefits of

proposed limitations for the coastal

subcategory of the oil and gas extraction

industry on the coastal environment.

The benefit analysis considers two

separate geographic areas: Gulf of

Mexico (Louisiana and Texas) and Cook

Inlet, Alaska. The benefit analysis

examines potential impacts from current

produced water discharges in both

geographic areas, and from drilling

fluids and drill cuttings discharges in

Cook Inlet. Effect of drilling fluids and

drill cutting discharges are not

evaluated for Gulf of Mexico coastal

operations since they are prohibited by

state authorities and existing NPDES

permits. Three types of benefits are

analyzed: quantified and nonmonetized, quantified and monetized,

and non-quantified and non-monetized

benefits.

Coastal waters maintain diverse

ecosystems which act as spawning

grounds, nurseries and habitats for

important estuarine and marine species

(finfish and shellfish); support highly

valuable commercial and recreational

fisheries; and provide critical habitat for

seabirds, shore birds and terrestrial

wildlife. The commercial fisheries in

Texas and Louisiana (finfish, shrimp,

crabs and oysters) were valued at $476

million in 1992. Commercial species

spend a significant portion of their life

cycle in bays and estuaries. The 1993

value of Cook Inlet commercial fisheries

(finfish, clams,crabs and shrimp) was

$48 million. Approximately $30 million

of this total was from Upper Cook Inlet

salmon fisheries. The estimated

consumer surplus associated with Cook

Inlet recreational fisheries is about $26

million per year (in 1993 dollars). In

addition, personal use and subsistence

fisheries provide food source and

cultural values to Alaskan residents and

Alaskan native populations. Coastal

waters also serve as critical habitats for

numerous federally designated

endangered and threatened species

(including 32 in coastal areas of Texas

and Louisiana) , and migrating

waterfowl.

Coastal waters are generally shallow,

where tidal action has limited effect,

and dilution and dispersion are more

limited than offshore waters.

Additionally, pollutants can migrate

much more readily into sediments,

where they may have long residence

times. Consequently, these receiving

environments are highly sensitive to

pollutant discharges compared to open

offshore areas. Many of the pollutants in

coastal oil and gas discharges are either

conventional pollutants, aquatic

toxicants, human carcinogens, or human

systemic toxicants. The impact of these

pollutants on aquatic biota include

acute toxicity; chronic toxicity; effects

on reproductive functions; physical

destruction of spawning and feeding

habitats; and loss of prey organisms. In

addition, many of these pollutants are

persistent, resistant to biodegradation

and accumulate in aquatic organisms.

Chemical contamination of aquatic biota

may also directly or indirectly impact

local aquatic and terrestrial wildlife and

humans consuming exposed biota.
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9471

Conventional pollutants, such as TSS

and oil & grease can have adverse effects

on human health and environment. For

example, habitat degradation can result

from increased suspended particulate

matter that reduces light penetration

and thus primary productivity.

Suspended solids in the water column

can have a direct effect on the fish either

killing them, or reducing their growth

rate and/or resistance to disease,

preventing successful development of

fish eggs and larvae, modifying fish

movement and migration and reducing

the abundance of food available to fish.

Settleable materials which blanket the

bottom of the water bodies cause

benthic smothering, damage

invertebrate populations and can alter

spawning grounds and feeding habitat.

Oil and grease can have lethal effect on

fish, by coating surface gills causing

asphyxia, or depleting oxygen levels

due to excessive biological demand, or

reducing reaeration because of surface

film. Oil and grease can also have

detrimental effects on waterfowl by

destroying the buoyancy and insulation

of their feathers. Bioaccumulation of oil

substances can cause human health

problems including tainting of fish and

bioaccumulation of carcinogenic

polycyclic aromatic compounds.

Benefits of this proposed rule include

elimination of toxic, conventional, and

nonconventional pollutants, or

reduction to levels below those

considered to impact receiving water’s

biota, and elimination or reduced

impacts on human health. Potential

benefits may ultimately include reduced

aquatic habitat degradation; improved

recreational fisheries; improved

subsistence and personal use fisheries

(important to low-income anglers and

Alaska’s Native anglers, etc.); improved

commercial fisheries; improved

aesthetic quality of waters; improved

recreational opportunities; and

decreased harm to threatened or

endangered species in Gulf of Mexico

and Cook Inlet.

B. Quantitative Estimate of Benefits

(1) Gulf of Mexico. The Gulf of

Mexico benefits associated with

produced water include: (a) nonmonetized benefits (i.e., (i) review of

case studies of environmental impacts

of produced water that document

adverse chemical and biological impacts

resulting from its discharge into coastal

waters in the Gulf of Mexico; (ii)

modeled water quality benefits

expressed as reduction/elimination in

exceedances of human health or aquatic

life state water quality standards; and

(iii) estimated reduction of total point

source toxic loading contribution to

Texas and Louisiana estuarine drainage

systems, and (b) monetized benefits (i.e.,

(i) estimated reduction of carcinogenic

risk from consumption of seafood

contaminated with Ra226 and Ra228

based on limited observations and

modeled levels; and (ii) estimated

ecological benefits of zero discharge of

produced water.))

(a) Quantified Non-Monetized

Benefits.

(i) Documented Case Studies. A

comprehensive review of available data

identified 25 study sites (12 in

Louisiana and 13 in Texas) that

examined impacts of produced water

discharges on coastal environment. The

majority of evaluated study sites are in

water depths less than 3 meters, and

include variable environments (i.e.,

wetlands, saltmarshes, and fresh or

brackish marshes), and both relatively

low and high energy areas. The

documented impacts show elevated

hydrocarbons and metals in water

column and sediments, and reveal

impacts on biota (i.e., depressed

community structure such as abundance

or diversity) up to 1,000 meters (and

more) from the produced water

discharge. The salinity effects are

typically detected up to 300 meters from

the discharge, and up to 800 meters in

dead-end canals. A benthic dead zone

(no benthic fauna) is documented up to

15 meters and severely depressed

benthic communities are noted to 150 to

400 meters from produced water

outfalls.

(ii) Projected Water Quality Benefits.

The effects of toxic pollutants in current

(BPT) produced water discharges on

receiving water quality and benefits of

proposed effluent guidelines are

evaluated. Plume dispersion modeling

is performed to project in-stream

concentrations of 66 pollutants

(representing subcategory-wide

produced water discharge) at the edge of

the state-prescribed mixing zones for

Texas and Louisiana at one and three

meters water depths. The in-stream

concentrations are compared to Texas

and Louisiana state standards; Texas has

standards for 12 of the pollutants and

Louisiana for 14. The results based on

the mean discharge rate show one

pollutant (silver) in Texas exceeds its

chronic standard at the one meter depth;

in Louisiana, one pollutant (copper)

exceeds two acute standards (daily

average and maximum), two pollutants

(copper and lead) exceed two chronic

standards, and one pollutant (benzene)

exceeds two human health standards at

the one meter depth, and at three meter

depth one pollutant (copper) exceeds its

acute standard, and one pollutant

(benzene) exceeds two human health

standards at the three meter depth. The

proposed BAT zero discharge option

would eliminate all projected

exceedances.

(iii) Projected Reduction of Point

Source Toxic Loading Contribution to

Texas and Louisiana Estuarine Drainage

Systems. The watershed pollutant

loadings from produced water are

compared to other industrial and

municipal point sources (i.e., excluding

pollutant loadings from nonpoint

sources and atmospheric deposition) for

Texas and Louisiana estuarine drainage

systems. At the current (BPT) discharge

level, produced water in Texas

contributes about 20 percent, and in

Louisiana about 60 percent of total point

source mass pollutant loadings into

their respective watersheds. The

proposed zero discharge would

eliminate produced water pollutant

loading contribution to the Texas and

Louisiana coastal watershed.

(b) Quantified Monetized Benefits. (i)

Projected Cancer Risk Reduction

Benefits. Upper bound individual

cancer risks from consuming fish

contaminated with Ra226 and Ra228 from

current produced water discharges are

estimated for recreational and

subsistence anglers, and aggregate

human cancer risks are projected and

monetized. Risks are estimated using

two types of data: (1) Measured field

seafood data (i.e., because background

levels could not be adequately

determined average Ra226 and Ra228

levels were used based on field samples

of fish, crabs and oysters collected

within 3,000 meters of produced water

discharges in coastal subcategory areas

of Louisiana), and (2) modelled effluent

data (i.e., using current subcategorywide produced water concentrations of

Ra226 and Ra228 and plume dispersion

model at mean outfall discharge rates to

estimate Ra226 and Ra228 levels in

seafood). [Using the estimated Ra226 and

Ra228 concentrations in seafood, EPA

estimates individual cancer risks

assuming two different consumption

rates of 147.3 g/day for subsistence

anglers and 15 g/day for recreational

anglers]. In addition, all individual

cancer risks are adjusted by factors of

0.2 and 0.75 to account for ingestion of

seafood from locations some of which

are not contaminated with the Ra226 and

Ra228 in coastal produced water

discharges. Projected individual cancer

risks for both risk assessment

approaches are at 10-4 level for

subsistence anglers, and at 10-6 level

recreational anglers. The proposed zero

discharge of produced water will

eliminate these estimated cancer risks

over time. Based on measured field data,

the proposed BAT is projected to
9472 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

eliminate 1.1 to 4.3 annual cancer cases

and the monetized benefits from cancer

cases avoidance are projected to range

from $2.3 to $43 million. Using the

modelling approach, the proposed BAT

is projected to eliminate 1.2 to 4.6

cancer cases per year, resulting in

monetized benefits in $ 2.4 to $46

million per year.

The temporal dynamics of both

impacts and benefits assessments is

relevant to the human health risk

assessment. For the assessments of

cancer reduction benefits, the

methodology is consistent with

estimating costs for the rule, using a

one-year ‘‘snap-shot’’ approach.

Allocating the full value of annual

benefits within one year following

cessation of produced water discharges

may appear to over-estimate potential

annual benefits in cases where

incomplete recovery has occurred.

However, in such cases where impacts

are incompletely recovered, a

consideration of total impact would

need to include any impacts expected to

occur beyond that year. This analysis

does not attempt to identify or allocate

benefits on a yearly basis, but merely

averages total benefits so that monetized

benefits may be compared to costs that

are developed using the same approach.

(ii) Projected Ecological Benefits for

Texas and Louisiana Bays. A potential

ecological benefit of zero discharge of

produced water in Texas and Louisiana

coastal areas is projected from a Trinity

Bay case study. This study shows that

measures of total benthic abundance

and species richness are depressed by

discharges, up to distances between 1.7

kilometers and 4 kilometers from the

point of discharge. (Data on abundance

of other species, such as waterfowl were

not collected.) Taking into account the

severity of these impacts at different

distances, the equivalent acreage

affected in this case study ranges from

200 to 2,817 acres. Extrapolating from

this case study to the other sites that

would be affected by this rule, EPA

estimates that the total Texas and

Louisiana acreage affected ranges from

14,607 acres to 195,488 acres. EPA

identified numerous values for an acre

of wetland but none were marginal

estimates for Texas or Louisiana, and

some did not net out the cost of

recreational use. A literature review for

wetland value estimates conducted for

Mineral Management Services (MMS) in

1991, reports that different studies have

estimated recreational and commercial

wetland values for coastal Louisiana

ranging from $57 to $940 per acre per

year (with a median value of $410 per

acre per year) in 1990 dollars. Using this

range of values, the estimated increase

of Texas and Louisiana Bay recreational

values ranges from $0.8 million to $184

million per year in 1990 dollars ($1.0

million to $210 million in 1994 dollars).

These per acre estimates are consistent

with the estimated average recreational

value of the acreage of Galveston Bay,

which ranges from $336 to $730 per

acre. (The Galveston Bay estimates do

not net out the cost to recreational users

of using the resource.) These estimates

may not be marginal values as they are

calculated from the total recreational

value of Galveston Bay and total acreage

of the Bay. There may be concern that

the value of wetland recovery

diminishes as the amount of recovered

acreage increases and therefore these

average values would overstate the

relevant marginal values by an

unknown amount. As these studies use

different estimation methods, cover

different types of wetlands, marshes and

coastal waters which may differ from

those affected by this rule, and generally

reflect average values rather than the

social valuation of small (marginal)

changes in acreage, EPA solicits

comments on the appropriateness of this

benefit analysis and requests data on

marginal values of wetlands, in

particular in Texas and Louisiana.

(iii) Total Monetized Benefits. EPA

estimates that total monetized benefits

(i.e. combining cancer risk reduction

and ecological benefits) resulting from

proposed zero discharge of produced

water range from approximately $3.2 to

$230 million per year in 1990 dollars

($3.7 million to $263 million in 1994

dollars).

(2) Cook Inlet. Quantified benefits

analyzed in Cook Inlet include nonmonetized quantified benefits

associated with proposed regulations of

produced water and drilling fluids and

drill cuttings. These benefits include

modeled water quality benefits

expressed: (a) as a reduction of mixing

zone needed for produced water

discharges to meet Alaska state water

quality standards, and (b) as a reduction

or elimination in exceedances of Alaska

state water quality standards at the edge

of mixing zone from drilling fluids and

drill cutting discharges.

(a) Produced Water. The effects of

toxic pollutants in current (BPT)

produced water discharges on receiving

water quality and benefits of proposed

effluent guidelines are evaluated. Plume

dispersion modeling is performed to

project in-stream concentration of 21

pollutants at the edge of the mixing

zones from eight outfalls representing

Cook Inlet produced water discharge;

the in-stream concentrations are then

compared to the Alaska’s state

limitations. Unlike the Gulf of Mexico,

Alaska state requirements do not have

spatially-defined mixing zones. (Alaska

determines the extent of the mixing

zone needed to achieve compliance

with water quality standards and

evaluates reasonableness of this

calculated mixing zone). The water

quality assessment for Cook Inlet

therefore determines the spatial extent

of mixing zones needed for each

evaluated outfall to meet all state

standards at current discharge and at the

proposed BAT. For the eight outfalls

modeled, the distance from each facility

where all state standards are met ranges

from within 50 feet to 2,500 meters at

current (BPT) level, and from within 50

feet to 2,000 meters at proposed BAT.

(b) Drilling Fluids and Drill Cuttings.

Discharges of drilling fluids and drill

cuttings are modelled using Offshore

Operator’s Committee (OOC) Mud

Discharge Model to project in-stream

concentrations of 19 pollutants in water

column at the edge of a 100 meter

mixing zone. The projected pollutant

concentrations are then compared to the

Alaska state water quality standards.

The discharge rates are modeled in

accordance with the maximum

discharge rates allowable under the

existing NPDES general permit for Cook

Inlet (1,000 bph in water depths

exceeding 40 meters; 750 bph in water

depths from 20 to 40 meters; and 500

bph in water depths from 5 to 20

meters). Discharges are prohibited in

waters between the shore and the 5

meter isobath. The modeling results

show four standards are exceeded

(human health standards for beryllium

and fluorene and the drinking water

standards for aluminum and iron) at 40

meter water depth; at 20 meters water

depth five standards are exceeded

(human health standards for beryllium,

fluorene, and phenanthrene, and

drinking water standards for aluminum

and iron); and six standards are

exceeded at the 10 meters water depth

(human health standards for beryllium,

fluorene, and phenanthrene, and

drinking water standards for aluminum,

antimony, and iron) at both current BPT

discharge and the alternative BAT

Option 2 which would allow discharge

of drilling fluids and drill cuttings with

certain limitations. The zero discharge

option (Option 3) would eliminate all

projected exceedances.

C. Description of Non-Quantified

Benefits

The Benefit Analysis attempts to

quantify, and whenever appropriate, to

monetize specific environmental

benefits that may result from the options

proposed for this rule. However, some

of the potential benefits could not be
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9473

quantified or monetized because of the

lack of data, or because sufficient

information to define the causal

relationship between coastal oil and gas

production activities and environmental

effects is not available. The evaluated

non-quantified benefits include: (1) an

analysis of environmental equity issues

related to this rulemaking; (2) effects on

threatened or endangered species and

migratory waterfowl, and potential

benefits from the proposed rule for

ecosystem health for coastal areas of

Gulf of Mexico and Cook Inlet.

(1) An Analysis of Environmental

Equity Issues. An analysis of potential

impacts on socioeconomic and ethnic

groups in coastal areas of Texas,

Louisiana, and Cook Inlet conducted to

address environmental equity issues

related to the discharges from coastal oil

and gas facilities indicates that the

subsistence and personal use of fisheries

in both geographic areas may be

appreciable, indicating potential

environmental equity concerns for low

income subsistence and personal use

anglers including Alaska’s Native

populations. These socioeconomic and

ethnic groups are known to be frequent

recreational or subsistence anglers and

are consuming a high rate of seafood,

and could consequently be at higher

than average risk, providing they

consume seafood that may be

contaminated with coastal oil and gas

pollutants. The subsistence and

personal use fisheries in these areas also

provide food sources that would

otherwise have to be purchased

elsewhere. In addition, Cook Inlet

fisheries are of cultural value to Alaskan

Native populations in that they allow

the continuance of a traditional lifestyle

dependent on the natural resources of

the Inlet. A zero discharge and control

of discharges of produced water, and

zero discharge of drilling fluids and

drill cuttings, and well treatment,

workover and completion fluids

discharges would reduce these impacts.

(2) Effects on Threatened and

Endangered Species. The proposed

regulation may also have beneficial

effects on 32 threatened and endangered

species in coastal area of Texas and

Louisiana (such as Brown Pelican,

Hawksbill Sea Turtle, Leatherback Sea

Turtle, Ocelot, and others) that use these

areas as part of their habitat. The Upper

Cook Inlet is an important pathway for

spawning fish and nonendangered

mammals which are resident or occur

seasonally in Cook Inlet including sea

lion, fur seal, harbor seal, sea otter and

beluga whale. The Cook Inlet area is

also a critical habitat for seabirds,

shorebirds, and migrating waterfowl,

including the Cackling Canada Goose,

Pacific Black Brant, Emperor Goose, and

Tule Goose. There are at least four

endangered cetacean species which may

occur in or near Cook Inlet. These

include the humpback whale, fin whale,

sei whale, and gray whale. Endangered

avian species which may occur as

migrants in or near Cook Inlet include

the short-tailed albatross, American

peregrine falcon, and Arctic peregrine

falcon. Control of produced water and

treatment, workover, and completion

fluids discharges and zero discharge of

drilling fluids and drill cuttings, would

reduce these impacts.

D. EPA Region VI Production Permit

The benefits of the proposed rule

evaluated in the benefit analysis are

based on discharges and discharge

locations that were projected for the

proposed guidelines (without the

published final Region 6 NPDES

General permits regulating produced

water discharges to coastal waters in

Louisiana and Texas in effect). Because

of the close timing of the publication of

these final General permits and the

proposed effluent guidelines, little

opportunity for in-depth re-analysis of

environmental benefits occurred. The

approach selected is to proportionate

quantified benefits based on a simple

flow proportion (i.e., the 29 percent

share of produced water flow),

attributable to the facilities excluded

from coverage under the General

permits but covered by the proposed

effluent guidelines. Using this approach,

EPA estimates that with the Region 6

General permits final, quantified

monetized benefits may be in the $0.9

to $67 million range in 1990 dollars

($1.1 to $76 million in 1994 dollars).

EPA will re-evaluate environmental

benefits of the coastal oil and gas

subcategory effluent guidelines upon

promulgation of the final rule.

XIII. Regulatory Implementation

A. Toxicity Limitation for Drilling Fluids

and Drill Cuttings

Under the alternative option EPA

considered for drilling fluids and drill

cuttings, EPA would establish a toxicity

limit for this waste stream. The toxicity

limitation would apply to any periodic

blowdown of drilling fluid as well as to

bulk discharges of drilling fluids and

drill cuttings systems. The reader is

referred to the Offshore Guidelines (58

FR, March 4, 1993, page 12502) for an

explanation of the regulatory

implementation for the toxicity limit.

B. Diesel Prohibition for Drilling Fluids

and Drill Cuttings

Under EPA’s alternative option for

drilling fluids and drill cuttings, diesel

oil and muds and cuttings contaminated

with diesel would be prohibited from

discharge from Cook Inlet oil platforms.

The reader is referred to the Offshore

Guidelines (58 FR 12502) for a

discussion on the implementation of

this requirement.

C. Upset and Bypass Provisions

A recurring issue of concern has been

whether industry guidelines should

include provisions authorizing

noncompliance with effluent limitations

during periods of ‘‘upsets’’ or

‘‘bypasses’’. The reader is referred to the

Offshore Guidelines (58 FR 12501) for a

discussion on upset and bypass

provisions.

D. Variances and Modifications

Once this regulation is in effect, the

effluent limitations must be applied in

all NPDES permits thereafter issued to

discharges covered under this effluent

limitations guideline subcategory.

Under the CWA certain variances from

BAT and BCT limitations are provided

for. A section 301(n) (Fundamentally

Different Factors) variance is applicable

to the BAT and BCT and pretreatment

limits in this rule. The reader is referred

to the Offshore Guidelines (58 FR

12502) for a discussion on the

applicability of variances.

E. Synthetic Drilling Fluids

During the Offshore Oil and Gas

Guidelines rulemaking, several industry

commenters noted recent developments

in formulating new (synthetic) drilling

fluids as substitutes for the traditional

water-based or oil-based fluids. The

newer drilling fluids provide improved

environmental and operational benefits

when compared to many of the

traditional fluids being used. The

industry commenters contended that the

new drilling fluids are not being used

due to potential interpretation of

effluent guidelines and permit

limitations. Prohibitions on the use of

oil-based fluids and inverse emulsions

were identified as potential barriers to

use. Commenters also specifically

identified the sheen test, which is used

to prohibit the discharge of fluids and

cuttings containing free oil, as giving

false positive results due to a

discoloration which may occur when

cuttings containing small amounts of

some of the synthetic fluids are

discharged.

Since the promulgation of the

Offshore Guidelines, data have been

submitted to document the enhanced
9474 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

environmental performance of synthetic

fluids. These data show lower toxicity

than several of the generic fluids used

as the basis for the offshore toxicity

limit of 30,000 ppm (SPP). Results of

laboratory and field (seabed) evaluations

of the biodegradation of one synthetic

fluid demonstrated good

biodegradation. Case histories of field

use have documented enhanced

operational and environmental

performance, which can include

reductions in waste generated and

improvement of non-water quality

impacts. Laboratory data have indicated

no detectable priority pollutants to be

present in synthetic fluids.

In the preamble to the March 4, 1993,

final Offshore Guidelines (58 FR 12496),

EPA identified several issues raised by

commenters for which additional

information was solicited. While EPA

wishes to encourage the use of less toxic

drilling fluids, EPA was concerned that

without a substitute for the static sheen

test, it would not be possible to enforce

the no free oil limit. EPA also solicited

specific data concerning the toxicity of

new synthetic drilling fluids.

Subsequently, several industry

companies have submitted additional

information. EPA has reviewed this

information and is conducting

additional work to further evaluate the

issues. This work is related to the

analytical capability to identify the

synthetic fluids versus diesel, mineral

or crude (formation) oils which may

cause a sheen when used fluids or

cuttings are discharged and the toxicity

of the synthetic fluids. Results of the

submitted analytical methods

investigations, summarized gas

chromatography mass copy (GC/MS)

identification of polyalphaolafin

synthetic fluids. The usefulness and

limitations of the methods were

discussed. Use of GC equipment shows

promise for detecting low

concentrations of oil in synthetic fluids,

e.g., less than 1 percent, but requires

further evaluation. Based on the results

of the initial work and work performed

as part of the final Offshore Guidelines

to differentiate between mineral oil and

diesel oil (58 FR 12502), the ‘‘methods

for the determination of Diesel, Mineral

and Crude Oils in Offshore Oil and Gas

Industry Discharges’’ (EPA 821–R–92–

008) may be useful, with or without

slight modifications, as an alternative or

verification step to the free oil and

diesel oil discharge prohibitions.

EPA solicits data on the use to-date of

synthetic fluids and any data, including

well logs, toxicity and analytical

methods testing and in-situ seabed and

water column physical, chemical and

biological testing. EPA will evaluate all

submitted data, including information

in the offshore rulemaking record, in

order to assess the environmental and

performance benefits that could be

achieved by using synthetic fluids, and

take those regulatory actions that may

be appropriate to mitigate or eliminate

barriers to using these fluids.

F. Removal Credits for Indirect

Dischargers

Many industrial facilities discharge

large quantities of pollutants to POTWs

where their wastewaters mix with

wastewater from other sources,

domestic sewage from private

residences and run-off from various

sources prior to treatment and discharge

by the POTW. Industrial discharges

frequently contain pollutants that are

generally not removed as effectively by

treatment at the POTWs as by the

industries themselves.

The introduction of pollutants to a

POTW from industrial discharges may

pose several problems. These include

potential interference with the POTW’s

operation or pass-through of pollutants

if inadequately treated. As discussed,

Congress, in section 307(b) of the Act,

directed EPA to establish pretreatment

standards to prevent these potential

problems. Congress also recognized that,

in certain instances, POTWs could

provide some or all of the treatment of

an industrial user’s wastewater that

would be required pursuant to the

pretreatment standard. Consequently,

Congress established a discretionary

program for POTWs to grant ‘‘removal

credits’’ to their indirect dischargers.

The credit, in the form of a less stringent

pretreatment standard, allows an

increased concentration of a pollutant in

the flow from the indirect discharger’s

facility to the POTW.

Section 307(b) of the CWA establishes

a three-part test for obtaining removal

credit authority for a given pollutant.

Removal credits may be authorized only

if (1) the POTW ‘‘removes all or any part

of such toxic pollutant,’’ (2) the POTW’s

ultimate discharge would ‘‘not violate

that effluent limitation, or standard

which would be applicable to that toxic

pollutant if it were discharged’’ directly

rather than through a POTW and (3) the

POTW’s discharge would ‘‘not prevent

sludge use and disposal by such

[POTW] in accordance with section

[405].* * *’’ Section 307(b).

EPA has promulgated removal credit

regulations in 40 CFR 403.7. The United

States Court of Appeals for the Third

Circuit has interpreted the statute to

require EPA to promulgate

comprehensive sewage sludge

regulations before any removal credits

could be authorized. NRDC v. EPA, 790

F.2d 289, 292 (3rd Cir. 1986) cert.

denied. 479 U.S. 1084 (1987). Congress

made this explicit in the Water Quality

Act of 1987 which provided that EPA

could not authorize any removal credits

until it issued the sewage sludge use

and disposal regulations required by

section 405(d)(2)(a)(ii).

Additional discussion of the

availability of removal credits is

contained in the Coastal Technical

Development Document. This rule

proposes to establish pretreatment

standards for existing and new sources

as zero discharge for drilling fluids and

drill cuttings; produced water; well

treatment, workover, and completion

fluids; and deck drainage, and EPA’s

pretreatment regulations at 40 CFR

403.7(a)(i) limit such authorization to

when the POTW demonstrates and

continues to achieve consistent removal

of the pollutant in accordance with

403.7(b), it is highly unlikely that

removal credits would be available for

these discharges.

EPA welcomes comment on when and

how removal credits may be authorized

for the pollutants in the circumstances

of the coastal oil and gas subcategory.

XIV. Related Rulemakings

In addition to these Coastal

Guidelines, EPA is in the process of

developing other regulations that

specifically affect the oil and gas

industry. These other rulemakings,

summarized below, are in the

developmental stages, and have not, as

yet, been proposed. EPA’s offices are

coordinating their efforts with the intent

to monitor these related rulemakings to

assess their collective costs to industry.

A. National Emission Standards for

Hazardous Air Pollutants

National emission standards for

hazardous air pollutants (NESHAP) are

being developed for the oil and gas

production industry by EPA’s Office of

Air Quality, Planning and Standards

(OAQPS), under authority of section 112

(d) of the Clean Air Act as amended in

1990. Section 112 (d) of the Clean Air

Act directs the EPA to promulgate

regulations establishing hazardous air

pollutant (HAP) emissions standards for

each category of major and area sources

that has been listed by EPA for

regulation under section 112 (c). The

189 pollutants that are designated as

HAP are listed in section 112 (d). For

major sources, or facilities which emit

10 or more tons per year (TPY) of an

individual HAP pollutant or 25 or more

TPY of multiple HAPs, the air emission

standards are based on ‘‘maximum

achievable control technology’’ or

MACT.
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9475

Major sources within the coastal oil

and gas subcategory have been

identified by OAQPS as stand alone

glycol dehydrators, tank batteries, gas

plants, and offshore production

platforms. In most cases, OAQPS

believes that, in order to be a major

source, a coastal production facility

must have glycol dehydrators located

on-site: a production facility alone may

not produce enough emissions to be

classified as a major source.

EPA plans to propose MACT

standards for the oil and gas industry by

June 1995 and promulgate them by June

1996. OAQPS estimates that the total

cost of these standards will be $13

million. Offshore production platforms

are under the jurisdiction of the

Minerals Management Service and thus,

are not affected by these MACT

Standards. EPA solicits information

regarding the percentage of coastal oil

and gas operations that will be impacted

by this rule.

2. Area of Review Requirements for

Injection Wells

The Safe Drinking Water Act of 1974

(SDWA) charges EPA with protecting

underground sources of drinking water

(USDWs). As part of this mandate, EPA

developed a program, known as the

Underground Injection Control Program

(UIC), to regulate the underground

injection of produced water, and

promulgate regulations concerning the

construction, operation, and closure of

Class II injection wells. Such regulations

were originally promulgated in 1980 (45

FR 42500, June, 24, 1980).

As a result of a recent 5-year study on

the effectiveness of these regulations,

EPA concluded that more detailed

minimum national standards, than those

promulgated in 1980, are necessary to

prevent endangerment of USDWs.

EPA is currently in the process of

developing such national standards that

would establish:

* A minimum national standard for

well construction,

* More frequent mechanical integrity

testing when the construction of a well

does not meet that minimum standard,

and

* A requirement for Area of Review

studies for wells located in areas where

USDWs are subject to significant risk of

indirect flow via improperly

constructed or abandoned wells.

The schedule for proposal and

promulgation of this rulemaking is not

specified. Early estimates are that these

UIC requirements would cost less than

$50 million per year for the entire U.S.

oil and gas industry for the first 5 years

after promulgation, and are expected to

decrease after 5 years.

It is not known at this time what

percentage of this cost will be incurred

by the coastal oil and gas industry. EPA

solicits comment regarding this.

3. Spill Prevention, Control, and

Countermeasure

EPA’s Oil Pollution Prevention

regulation at 40 CFR part 112, otherwise

known as the Spill Prevention, Control,

and Countermeasure (SPCC) regulation

was promulgated in 1973 under section

311 (j) of the CWA. The SPCC regulation

applies to all oil extraction and

production facilities that have an oil

storage capacity above certain

thresholds (i.e. an overall aboveground

oil storage capacity greater than 1,320

gallons or greater than 660 in a single

container, or an underground oil storage

capacity of greater than 42,000 gallons)

and are located such that a discharge

could reasonably be expected to reach

U.S. waters. EPA estimates that there are

approximately 435,000 SPCC-regulated

facilities. Approximately 3,000 of these

facilities are either coastal or offshore

facilities.

Under the SPCC regulations, facility

owners or operators are required to

prepare and implement written SPCC

plans that discuss conformance with

procedures, methods, and equipment

and other requirements to prevent

discharge of oil and to contain such

discharges.

On July 1, 1994, (59 FR 34070, July 1,

1994) EPA issued a final rule for certain

onshore facilities to prepare, submit to

EPA, and implement plans to respond to

a worst case discharge of oil to meet

section 4202(a) of the Oil Pollution Act

(OPA). EPA is in the process of

developing requirements to meet

Section 420.2(a) of OPA specifically for

coastal facilities (Note: Coastal and

offshore facilities in the SPCC program

are collectively referred to as ‘‘offshore’’.

However, this current rulemaking is

specifically with respect to facilities

landward of the inner boundary of the

territorial seas, and that are not

onshore.) These regulations will, among

other things, require that owners or

operators of all coastal facilities prepare

and submit to the Federal government a

plan for responding to a worst case

discharge of oil.

EPA plans to propose these

requirements by 1995, and promulgate

them by 1996. Costs to the industry to

comply with these requirements are as

yet unknown. EPA solicits information

regarding the storage capacities of

coastal oil production facilities to

determine the percentage of this

industry under the Coastal Oil and Gas

subcategory that would be affected by

the SPCC regulations.

XV. Solicitation of Data and Comments

EPA encourages public participation

in this rulemaking and invites

comments on any aspect of these

proposed regulations. The EPA asks that

comments address any perceived

deficiencies in the record of this

proposal and that suggested revisions or

corrections be supported by data where

possible. The preceding parts of this

notice identify specific areas where

comments are solicited. In addition,

EPA particularly requests comments

and information on the following:

(1) Combining the Onshore and Coastal

Subcategories

EPA’s proposed coastal rule requires

zero discharge for all drilling fluids and

cuttings, as well as zero discharge for all

produced waters except from Cook Inlet

operations. Because the effluent

limitations for the onshore subcategory

of the oil and gas industry require zero

discharge for all oil and gas wastes (44

FR 22069, April 13, 1979), EPA is

considering the appropriateness of

combining these two subcategories for

regulation of the major wastestreams.

Combining the subcategories would not

only simplify the rule itself but, could

result in reduction of administrative

burden in permit development, and

facility location determination; EPA

solicits comment on the appropriateness

of combining these two subcategories.

XVI. Background Documents

The basis for this regulation is

detailed in two major documents, each

of which is supported in turn by

additional information and analyses in

the rulemaking record. EPA’s technical

foundation for the regulation is detailed

in the Development Document for

Proposed Effluent Limitations

Guidelines and Standards for the

Coastal Subcategory of the Oil and Gas

Extraction Point Source Category. EPA’s

economic analysis is presented in the

Economic Impact Analysis of Proposed

Effluent Limitations Guidelines and

Standards for the Coastal Subcategory of

the Offshore Oil and Gas Industry.

These documents are available from the

Office of Water Resource Center. (See

ADDRESSES) The public record for this

rulemaking is available for review at

EPA’s Water Docket. (See ADDRESSES)

Appendix A to the Preamble—

Abbreviations, Acronyms, and Other

Terms Used in This Document

Act—Clean Water Act.

Agency—Environmental Protection Agency.

BADCT—The best available demonstrated

control technology, for new sources under

section 306 of the Clean Water Act.
9476 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

BAT—The best available technology

economically achievable, under section

304(b)(2)(B) of the Clean Water Act.

bbl—barrel, 42 U.S. gallons.

bpd—barrels per day.

bpy—barrels per year.

BCT—Best conventional pollutant control

technology under section 304(b)(4)(B) of

the Clean Water Act.

BMP—Best management practices under

section 304(e) of the Clean Water Act.

BOD—Biochemical oxygen demand.

BOE—Barrels of oil equivalent.

BPT—Best practicable control technology

currently available, under section 304(b)(1)

of the Clean Water Act.

CFR—Code of Federal Regulations.

Clean Water Act—Federal Water Pollution

Control Act Amendments of 1972 (33

U.S.C. 1251 et seq.).

Conventional pollutants—Constituents of

wastewater as determined by section

304(a)(4) of the Clean Water Act, including,

but not limited to, pollutants classified as

biochemical oxygen demanding,

suspended solids, oil and grease, fecal

coliform, and pH.

CWA—Clean Water Act.

Direct discharger—A facility which

discharges or may discharge pollutants to

waters of the United States.

EIA—Economic Impact Analysis.

EPA—Environmental Protection Agency.

Indirect discharger—A facility that

introduces wastewater into a publicly

owned treatment works.

IRR—Internal Rate of Return.

LC50—The concentration of a test material

that is lethal to 50 percent of the test

organisms in a bioassay.

mg/l—milligrams per liter.

Nonconventional pollutants—Pollutants that

have not been designated as either

conventional pollutants or priority

pollutants.

NORM—Naturally Occurring Radioactive

Materials.

NPDES—The National Pollutant Discharge

Elimination System.

NPV—Net Present Value.

NSPS—New source performance standards

under section 306 of the Clean Water Act.

OCS—Offshore Continental Shelf.

OMB—Office of Management and Budget.

POTW—Publicly Owned Treatment Works.

ppm—parts per million.

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 Clean Water Act.

PSNS—Pretreatment standards for new

sources of indirect discharges, under

sections 307 (b) and (c) of the Clean Water

Act.

SIC—Standard Industrial Classification.

SPP—Suspended particulate phase.

TSS—Total Suspended Solids.

Coastal Technical Development Document—

Development Document for Proposed

Effluent Limitations Guidelines and New

Source Performance Standards for the

Coastal Subcategory of the Oil and Gas

Extraction Point Source Category.

Offshore Technical Development

Document—Development Document for

Effluent Limitations Guidelines and New

Source Performance Standards for the

Offshore Subcategory of the Oil and Gas

Extraction Point Source Category.

U.S.C.—United States Code.

List of Subjects in 40 CFR Part 435

Environmental protection, Oil and gas

extraction, Pollution prevention, Waste

treatment and disposal, Water pollution

control.

Dated: January 31, 1995.

Carol M. Browner,

Administrator.

For the reasons set forth in the

preamble, 40 CFR part 435 is proposed

to be amended as follows:

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 and 1361.

2. Subpart A is proposed to be

amended by revising § 435.10 to read as

follows:

Subpart A—Offshore Subcategory

§ 435.10 Applicability; description of the

offshore subcategory.

The provisions of this subpart are

applicable to those facilities engaged in

field exploration, drilling, well

production, and well treatment in the

oil and gas industry which are located

in waters that are seaward of the inner

boundary of the territorial seas

(‘‘offshore’’) as defined in section 502(g)

of the Clean Water Act.

3. Subpart G consisting of § 435.70 is

proposed to be added to read as follows:

Subpart G—General Provisions

§ 435.70 Applicability.

(a) Purpose. This subpart is intended

to prevent oil and gas facilities subject

to this part from circumventing the

effluent limitations guidelines and

standards applicable to those facilities

by moving effluent produced in one

subcategory to another subcategory for

disposal under less stringent

requirements than intended by this part.

(b) Applicability. The effluent

limitations and standards applicable to

an oil and gas facility shall be

determined as follows:

(1) An oil and gas facility, operator, or

its agent or contractor may move its

wastewaters from a facility located in

one subcategory to another subcategory

for treatment and return it to a location

covered by the original subcategory for

disposal. In such case, the effluent

limitations guidelines, new source

performance standards, or pretreatment

standards for the original subcategory

apply.

(2) An oil and gas facility, operator, or

its agent or contractor may move its

wastewaters from a facility located in

one subcategory to another subcategory

for disposal or treatment and disposal,

provided:

(i) If an oil and gas facility, operator

or its agent or contractor moves

wastewaters from a wellhead located in

one subcategory to another subcategory

where oil and gas facilities are governed

by less stringent effluent limitations

guidelines, new source performance

standards, or pretreatment standards,

the more stringent effluent limitations

guidelines, new source performance

standards, or pretreatment standards

applicable to the subcategory where the

wellhead is located shall apply.

(ii) If an oil and gas facility, operator

or its agent moves effluent from a

wellhead located in one subcategory to

another subcategory where oil and gas

facilities are governed by more stringent

effluent limitations guidelines, new

source performance standard, or

pretreatment standards, the more

stringent effluent limitations guidelines,

new source performance standards, or

pretreatment standards applicable at the

point of discharge shall apply.

4. Subpart D is proposed to be

amended by revising §§ 435.40 and

435.41 to read as follows:

Subpart D—Coastal Subcategory

§ 435.40 Applicability; description of the

coastal subcategory.

The provisions of this subpart are

applicable to those facilities engaged in

field exploration, drilling, well

production, and well treatment in the

oil and gas industry in areas defined as

‘‘coastal.’’ The term coastal means:

(a) Any oil and gas facility located in

or on a water of the United States

landward of the territorial seas; or

(b)(1) Oil and gas facilities in

existence on April 13, 1979 or thereafter

and are located landward from the inner

boundary of the territorial seas and

bounded on the inland side by the line

defined by the inner boundary of the

territorial seas eastward of the point

defined by 89°45′ W. Longitude and

29°46′ N. Latitude and continuing as

follows west of that point:

Direction to west longitudeDirection to north latitude

West, 89°48′ .............. North, 29°50′.

West, 90°12′ .............. North, 30°06′.

West, 90°20′ .............. South, 29°35′.

West, 90°35′ .............. South, 29°30′.

West, 90°43′ .............. South, 29°25′.
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9477

Direction to west longitudeDirection to north latitude

West, 90°57′ .............. North, 29°32′.

West, 91°02′ .............. North, 29°40′.

West, 91°14′ .............. South, 29°32′.

West, 91°27′ .............. North, 29°37′.

West, 92°33′ .............. North, 29°46′.

West, 91°46′ .............. North, 29°50′.

West, 91°50′ .............. North, 29°55′.

West, 91°56′ .............. South, 29°50′.

West, 92°10′ .............. South, 29°44′.

West, 92°55′ .............. North, 29°46′.

West, 93°15′ .............. North, 30°14′.

West, 93°49′ .............. South, 30°07′.

West, 94°03′ .............. South, 30°03′.

West, 94°10′ .............. South, 30°00′.

West, 94°20′ .............. South, 29°53′.

West, 95°00′ .............. South, 29°35′.

West, 95°13′ .............. South, 29°28′.

East, 95°08′ ............... South, 29°15′.

West, 95°11′ .............. South, 29°08′.

West, 95°22′ .............. South, 28°56′.

West, 95°30′ .............. South, 28°55′.

West, 95°33′ .............. South, 28°49′.

West, 95°40′ .............. South, 28°47′.

West, 96°42′ .............. South, 28°41′.

East, 96°40′ ............... South, 28°28′.

West, 96°54′ .............. South, 28°20′.

West, 97°03′ .............. South, 28°13′.

West, 97°15′ .............. South, 27°58′.

West, 97°40′ .............. South, 27°45′.

West, 97°46′ .............. South, 27°28′.

West, 97°51′ .............. South, 27°22′.

East, 97°46′ ............... South, 27°14′.

East, 97°30′ ............... South, 26°30′.

East, 97°26′ ............... South, 26°11′.

(2) East to 97°19′ W. Longitude and

Southward to the U.S.—Mexican border.

§ 435.41 Specialized definitions.

For the purpose of this subpart:

(a) Except as provided in this section,

the general definitions, abbreviations

and methods of analysis set forth in 40

CFR part 401 shall apply to this subpart.

(b) The term average of daily values

for 30 consecutive days is the average of

the daily values obtained during any 30

consecutive day period.

(c) The term Cook Inlet means all of

the production platforms (‘‘existing

sources’’ or ‘‘existing dischargers’’) and

exploratory operations (‘‘new

dischargers’’) addressed by EPA’s

Region X in the general NPDES permit

for Cook Inlet.

(d) The term daily values as applied

to produced water effluent limitations

and NSPS refers to the daily

measurements used to assess

compliance with the maximum for any

one day.

(e) The term deck drainage refers to

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.

(f) The term development facility

means any fixed or mobile structure

subject to this subpart that is engaged in

the drilling of productive wells.

(g) The term dewatering effluent

means wastewater from drilling fluids

and 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).

(h) The term 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, N.W., Suite 700, Washington,

DC.

(i) The term domestic waste refers to

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.

(j) The term drill cuttings refers to the

particles generated by drilling into

subsurface geologic formations and

carried to the surface with the drilling

fluid.

(k) The term drilling fluid refers to the

circulating fluid (mud) used in the

rotary drilling of wells to clean and

condition the hole and to

counterbalance formation pressure. A

water-based drilling fluid is the

conventional drilling mud in which

water is the continuous phase and the

suspending medium for solids, whether

or not oil is present. An oil-based

drilling fluid has diesel oil, mineral oil,

or some other oil as its continuous

phase with water as the dispersed

phase.

(l) The term 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.

(m) The term 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.

MARPOL 73/78 is available from the

National Technical Information Service

(NTIS) (reference number ADA 183

505), 5285 Port Royal Road, Springfield,

VA 22161.

(n) The term 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.

(o) The term 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.

(p) The term 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.

The term 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.

(q) The term M9IM means those

coastal facilities continuously manned

by nine (9) or fewer persons or only

intermittently manned by any number

of persons.

(r) The term M10 means those coastal

facilities continuously manned by ten

(10) or more persons.

(s)(1) The term 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) The term water area as used in the

term ‘‘site’’ in 40 CFR 122.29 and 122.2

means the water area and ocean floor

beneath any exploratory, development,

or production facility where such

facility is conducting its exploratory,

development or production activities.

(ii) The term significant site

preparation work as used in 40 CFR

122.29 means the process of surveying,

clearing or preparing an area of the

ocean 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 this subpart pending
9478 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

EPA issuance of a new source NPDES

permit.

(t) The term no discharge of free oil

means that waste streams may not be

discharged when they would cause a

film or sheen upon or a discoloration of

the surface of the receiving water or fail

the static sheen test defined in

Appendix 1 to 40 CFR part 435, subpart

A.

(u) The term produced sand refers to

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.

(v) The term produced water refers to

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.

(w) The term 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.

(x) The term sanitary waste refers to

human body waste discharged from

toilets and urinals located within

facilities subject to this subpart.

(y) The term static sheen test refers to

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 to 40 CFR part 435, subpart

A.

(z) The term 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 40 CFR part 435, subpart

A.

(aa) The term well completion fluids

refers to 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.

(bb) The term well treatment fluids

refers to any fluid used to restore or

improve productivity by chemically or

physically altering hydrocarbon-bearing

strata after a well has been drilled.

(cc) The term workover fluids refers to

salt solutions, weighted brines,

polymers, or other specialty additives

used in a producing well to allow for

maintenance, repair or abandonment

procedures.

(dd) The term 96-hour LC50 refers to

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.

5. Section 435.42 is proposed to be

amended by revising the introductory

text and be in the table to paragraph (a)

by adding at the end an entry for

‘‘Produced Sand’’ 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).

Except as provided in 40 CFR 125.30

through 125.32, any existing point

source subject to this subpart must

achieve the following effluent

limitations representing the degree of

effluent reduction attainable by the

application of the best practicable

control technology currently available.

(a) * * *

BPT EFFLUENT LIMITATIONS

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

* * * * * * *

Produced Sand ............................................................... zero discharge .................................. zero discharge .................................. NA

* * * * *

6. Sections 435.43 through 435.47 are

proposed to be added to subpart D 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).

Except as provided in 40 CFR 125.30

through 125.32, any existing point

source subject to this Subpart must

achieve the following effluent

limitations representing the degree of

effluent reduction attainable by the

application of the best available

technology economically achievable

(BAT):

BAT EFFLUENT LIMITATIONS

Stream Pollutant parameter BAT effluent limitations

Produced Water:

(A) All coastal areas except Cook Inlet ...... .................................... No discharge.

(B) Cook Inlet ............................................. Oil & Grease .............. The maximum for any one day shall not exceed 42 mg/l, and the 30-

day average shall not exceed 29 mg/l.

Drilling Fluids and Drill Cuttings:

Option 1:

(A) All coastal areas except Cook Inlet ...... .................................... No discharge.

(B) Cook Inlet ............................................. Free Oil 1 .................... No discharge.

Diesel Oil ................... No discharge.

Mercury ...................... 1 mg/kg dry weight maximum in the stock barite.
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9479

BAT EFFLUENT LIMITATIONS—Continued

Stream Pollutant parameter BAT effluent limitations

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

Toxicity ....................... Minimum 96-hour LC50 of the SPP shall be 3 percent by volume.3

Option 2:

(A) All coastal areas except Cook Inlet ...... .................................... No discharge.

(B) Cook Inlet ............................................. Free Oil11 .................. No discharge.

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.

Toxicity ....................... Minimum 96-hour LC50 of the SPP shall be 10 percent to 100 percent

by volume.3

Option 3:

All coastal areas ......................................... .................................... No discharge.

Well Treatment, Workover and Completion

Fluids:

Option 1:

(A) All coastal areas except freshwater of

Texas and Louisiana.

Free Oil1 .................... No discharge.

(B) Freshwaters of Texas and Louisiana ... .................................... No discharge.

Option 2:

(A) All coastal areas except Cook Inlet ...... .................................... No discharge.

(B) Cook Inlet ............................................. Oil and Grease .......... The maximum for any one day shall not exceed 42 mg/l, and the 30-

day average shall not exceed 29 mg/l.

Produced Sand .................................................. .................................... No discharge.

Deck Drainage ................................................... Free Oil 2 .................... No discharge.

Domestic Waste ................................................. Foam .......................... No discharge.

1As determined by the static sheen test

2As determined by the presence of a film or sheen upon or a discoloration of the surface of the receiving water (visual sheen).

3As determined by the toxicity test (see appendix 2 of 40 CFR part 435, subpart A).

§ 435.44 Effluent limitations guidelines

representing the degree of effluent

reduction attainable by the application of

the best conventional pollutant control

technology (BCT).

Except as provided in 40 CFR 125.30

through 125.32, any existing point

source subject to this subpart must

achieve the following effluent

limitations representing the degree of

effluent reduction attainable by the

application of the best conventional

pollutant control technology (BCT):

BCT EFFLUENT LIMITATIONS

Stream Pollutant parameter BCT effluent limitations

Produced Water (all facilities) ............................ Oil & Grease .............. The maximum for any one day shall not exceed 72 mg/l and the 30-

day average shall not exceed 48 mg/l.

Drilling Fluids and Drill Cuttings:

All facilities except Cook Inlet .................... .................................... No discharge.

Cook Inlet ................................................... Free Oil ...................... No discharge.1

Well Treatment, Workover and Completion

Fluids.

Free Oil ...................... No discharge.1

Produced Sand .................................................. .................................... No discharge

Deck Drainage ................................................... Free Oil ...................... No discharge.2

Sanitary Waste:

Sanitary M10 .............................................. Residual Chlorine ...... Minimum of 1 mg/l maintained as close to this concentration as possible.

Sanitary M91M ........................................... Floating Solids ........... No discharge.

Domestic Waste ................................................. Floating Solids and

garbage.

No discharge of Floating Solids or garbage.3

1As determined by static sheen test 40 CFR part 435, subpart A, appendix 1.

2As determined by the presence of a film or sheen upon or a discoloration of the surface of the receiving water (visual sheen).

3As defined in 40 CFR 435.41(1).

§ 435.45 Standards of performance for

new sources (NSPS).

Any new source subject to this

subpart must achieve the following new

source performance standards (NSPS):
9480 Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules

NSPS EFFLUENT LIMITATIONS

Stream Pollutant parameter NSPS/PSNS effluent limitations

Produced Water (all facilities) ............................ .................................... No discharge.

Drilling Fluids and Drill Cuttings:

Option 1:

(A) All coastal areas except Cook Inlet ...... .................................... No discharge.

(B) Cook Inlet ............................................. Free Oil 1 .................... No discharge.

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.

Toxicity ....................... Minimum 96-hour LC50 of the SPP shall be 3 percent by volume.3

Option 2:

(A) All coastal areas except Cook Inlet ...... .................................... No discharge.

(B) Cook Inlet ............................................. Free Oil 1 .................... No discharge.

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.

Toxicity ....................... Minimum 96-hour LC50 of the SPP shall be 10 percent to 100 percent

to 100 percent by volume.3

Option 3:

All coastal areas ......................................... .................................... No discharge.

Well Treatment, Workover and Completion

Fluids:

Option 1:

(A) All coastal areas except freshwater of

Texas and Louisiana.

Free Oil 1 .................... No discharge.

(B) Freshwaters of Texas and Louisiana ... .................................... No discharge.

Option 2:

(A) All coastal areas except Cook Inlet ...... .................................... No discharge.

(B) Cook Inlet ............................................. Oil and Grease .......... The maximum for any one day shall not exceed 42 mg/l, and the 30-

day average shall not exceed 29 mg/l.

Produced Sand .................................................. .................................... No discharge.

Deck Drainage ................................................... Free Oil 2 .................... No discharge.

Sanitary Waste:

Sanitary M10 .............................................. Residual Chlorine ...... Minimum of 1 mg/l and maintained as close to this concentration as

possible.

Sanitary M91M ........................................... Floating Solids ........... No discharge.

Domestic Waste ................................................. Floating Solids, Garbage 4 and Foam.No discharge of floating solids or garbage or foam.

1As determined by the static sheen test.

2As determined by the presence of a film or sheen upon or a discoloration of the surface of the receiving water (visual sheen).

3As determined by the toxicity test (see appendix 2 of 40 CFR part 435, subpart A).

4As defined in 40 CFR 435.41(1).

§ 435.46 Pretreatment Standards of

performance for existing sources (PSES).

Except as provided in 40 CFR 403.7

and 403.13, any existing source with

discharges subject to this subpart that

introduces pollutants into a publicly

owned treatment works must comply

with 40 CFR part 403 and by the

effective date of this rule achieve the

following pretreatment standards for

existing sources (PSES).

PSES EFFLUENT LIMITATIONS

Stream Pollutant

parameter

PSES effluent

limitations

Produced Water ......................................................................................................................................................... .................... No discharge.

Drilling Fluids and Drill Cuttings ................................................................................................................................. .................... No discharge.

Well Treatment, Workover and Completion Fluids .................................................................................................... .................... No discharge.

Produced Sand .......................................................................................................................................................... .................... No discharge.

Deck Drainage ........................................................................................................................................................... .................... No discharge.

§ 435.47 Pretreatment Standards of

performance for new sources (PSNS).

Except as provided in 40 CFR 403.7

and 403.13, any new source with

discharges subject to this subpart that

introduces pollutants into a publicly

owned treatment works must comply

with 40 CFR part 403 and by the

effective date of this rule achieve the

following pretreatment standards for

new sources (PSNS).
Federal Register / Vol. 60, No. 33 / Friday, February 17, 1995 / Proposed Rules 9481

PSNS EFFLUENT LIMITATIONS

Stream Pollutant

parameter

PSNS effluent

limitations

Produced Water(all facilities) ..................................................................................................................................... .................... No discharge.

Drilling fluids and Drill Cuttings .................................................................................................................................. .................... No discharge.

Well Treatment, Workover and Completion Fluids .................................................................................................... .................... No discharge.

Produced Sand .......................................................................................................................................................... .................... No discharge.

Deck Drainage ........................................................................................................................................................... .................... No discharge.

[FR Doc. 95–3602 Filed 2–16–95; 8:45 am]

BILLING CODE 6560–50–P