Effluent Limitations Guidelines, Pretreatment Standards, and New Source Performance Standards: Oil and Gas Extraction Point Source Category, Coastal Subcategory

SUMMARY: This proposed regulation would limit the discharge of

pollutants into waters of the United States and the introduction of

pollutants into publicly-owned 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 company-specific 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 [[Page 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, [[Page 9430]] 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

[[Page 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. [[Page 9432]]

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 Sec. 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, non-water

quality environmental impacts (including energy requirements), and

other factors as the EPA Administrator deems appropriate. CWA

Sec. 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 ``cost-

reasonableness'' 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-of-process 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 technology-based 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 pass-

through that addresses localized rather than national instances of

pass-through and establish pretreatment standards that apply to all

non-domestic dischargers. See 52 FR 1586, January 14, 1987.

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 [[Page 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.

----------------------------------------------------------------------------------------------------------------

\1\The 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 [[Page 9434]] 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. [[Page 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 multi-well 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 man-made 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

----------------------------------------------------------------------------------------------------------------

Number of Number of

production operators

Number of Number of facilities that

producing production that would Annual would

Coastal location Region wells facilities incur drilling incur

(1992) (1992) costs activity costs

under this under

rule this rule

----------------------------------------------------------------------------------------------------------------

Gulf of Mexico...... TX & LA.......................... 4675 853 216 686 122

AL, FL........................... 56 ND\1\ 0 7 0

Alaska.............. Cook Inlet....................... 237 8 8 8 5

North Slope...................... 2085 12 0 161 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. [[Page 9436]] 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]

--------------------------------------------------------------------------------------------------------------------------------------------------------

Region VI

Region X exploration permit Region VI final production Region IV permit

Wastestream Region X (Cl 1986 BPT permit) (1993) drilling permit permit (final) (1994)

(1993) (1995)

--------------------------------------------------------------------------------------------------------------------------------------------------------

Produced Water........... Monitor daily flow rate Oil & Not applicable............... Covered in Production No Discharge.... No Discharge.

Grease: Phillips A Platform Permit.

20 mg/l daily max 15 mg/l mo.

ave. Other facilities: 48/72

mg/l pH=6-9.

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

Drilling Fluids and (1) Toxicity: Discharge only (1) Flowrate = 750 bbl/hr.... No Discharge......... Not applicable.. No Discharge.

Cuttings. approved generic muds.

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

(3) No discharge oil-based (3) Toxicity: 30,000 ppm in

muds. SPP.

(4) 10 percent oil content for (4) No free oil..............

cuttings.

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

fluids.

(6) 1/3 mg/kg Hg/Cd in dry (6) 5 percent (wt) oil

barite. 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.

[[Page 9437]]

>20-40m = 750 bbl/hr........

>5-20m = 500 bbl/hr.........

5 = 45 mg/l daily

sheen). 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. avg.) No free oil (visual Not applicable.. Monitor daily flow

Monitor flow rate (mo. ave.). No free oil (visual sheen). sheen) Monitor No free oil (visual

volume. sheen)

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

sheen). max.

As close as possible to, but No floating solids........... BOD = 45 mg/l........ BOD5 = 45 mg/l daily

no less than 1.0 mg/l. max.

BOD & SS2..................... No visible foam.............. TSS = 45 mg/l fecal = 30 mg/l (mo.

coliforms = 200/100 aver.)

mls Monitor flow. 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..........

[[Page 9438]]

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.

2Limits 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 non-hazardous

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

\1\The 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.

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 [[Page 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 [[Page 9440]] 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

[[Page 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 closed-loop 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 low-toxicity 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 [[Page 9442]] 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 VII-

VIII 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 on-land 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 on-land 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 [[Page 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 co-proposed.

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

[[Page 9444]] ``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 two-part 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

[[Page 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\

--------------------------------------------------------------------------------------------------------------------------------------------------------

Pollutant Compliance

Regulatory option removal (lb/ cost\1\ ($/ BCT cost ($/ Pass POTW (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.

\2\Net 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.

---------------------------------------------------------------------------

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 pre-

tax (although the financial models account for impacts based on the

appropriate post-tax costs). EPA re-emphasizes 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.

[[Page 9462]]

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$)

----------------------------------------------------------------------

(4) Annual compliance costs

($ million/yr)

--------------------------------------------

Wastestream\1\

(2) BAT

(1) NSPS

------------------------------------------------------------------------

Produced water.............

(2) 30.86

(1) 4.48

------------------------------------------------------------------------

(2) Co-proposal

(1)

---------------------------

Opt 1 Opt 2 Opt 3

(1) \2\ 0

---------------------------

Drilling fluids and

cuttings 0 1.4 3.89

(1)

------------------------------------------------------------------------

(2) Co-proposal

(1) Co-proposal

--------------------------------------------

Opt 1

(1) Opt 2 Opt 1 Opt 2

--------------------------------------------

Treatment, workover, and

completion fluids......... 0

(1) 0.61 0 0.52

------------------------------------------------------------------------

Total..................

(2) 30.86-35.36

(1) 4.48-5.00

------------------------------------------------------------------------

\1\EPA 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 [[Page 9463]] 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

\3\The 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.

---------------------------------------------------------------------------

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.

\4\The losses of $160.4 million included costs of technology and

resulting production losses.

---------------------------------------------------------------------------

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

[[Page 9464]] 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

----------------------------------------------------------------------------------------------------------------

Option Drilling waste TWC

No. 4 -------------------------------------------------------

Impact\1\ produced Total impacts\2\

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

lost production

(million BOE).

Total production 32.4 0 3.6 7.8 Negl. Negl. 32.4 to 40.2.

lost (million

BOE).

Present value of $153,209 0 $263 $6,089 Negl. Negl. $153,209 to $160,409.

producer income

lost ($000).

Present value of $84,903 0 $2,586 $7,925 Negl. Negl. $84,903 to $90,950.

federal taxes

lost ($000).

Present value of $10,676 0 $133 $272 Negl. Negl. $10,676 to $10,815.

lost severance

taxes ($000).

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

lost royalties

to states.

Total present $283,043 0 $7,256 $23,680 Negl. Negl. $283,043 to $301,549.

value losses

($000)\3\.

----------------------------------------------------------------------------------------------------------------

\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

[[Page 9465]] 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 shut-in wells tend to be relatively low-producing and marginal

wells.

\5\Total 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).

---------------------------------------------------------------------------

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-to-entry 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]

------------------------------------------------------------------------

Option No. 4

Impact 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.

\6\NSPS 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.

---------------------------------------------------------------------------

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 [[Page 9466]] existing platforms in Cook Inlet as

result of three wells not being drilled. The net present value of thi

This text is long and has been trimmed here. Open the source document for the complete record.