Final Effluent Limitations Guidelines and Standards for the Coastal Subcategory of the Oil and Gas Extraction Point Source Category

SUMMARY: This Clean Water Act (CWA) regulation limits 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 regulation establishes 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 regulation also establishes ``pretreatment standards for new

sources'' (PSNS) and ``pretreatment standards for existing sources''

(PSES) discharging their wastewaters to publicly-owned-treatment works

(POTWs). In essence, this final rule codifies the current permit

requirements for coastal oil and gas dischargers--except that it also

requires zero discharge of offshore produced water for discharges to

the main passes of the Mississippi River, applies to discharges not

currently authorized by permits, and establishes limitations in Cook

Inlet, Alaska which are equal to those previously established for the

offshore subcategory. The major wastestreams being limited are produced

water, drilling fluids, and drill cuttings. These limitations are

expected to reduce discharges of conventional pollutants by 2,780,000

pounds per year, nonconventional pollutants by 1,490,000,000 pounds per

year, and toxic pollutants by 228,000 pounds per year, assuming a

baseline of current permit requirements. The statutory term ``toxic

pollutant'' refers to a substance identified as belonging to one of the

65 families of chemicals listed in the CWA as toxic.

DATES: The regulation shall become effective January 15, 1997, except

for Sec. 435.45 NSPS which become effective December 16, 1996.

The compliance dates for the guidelines and standards established

with this rule are different. The compliance date for PSES is January

15, 1997. The compliance date for NSPS and PSNS is the date the new

source begins operation. Deadlines for compliance with BPT, BCT, and

BAT are established in NPDES permits.

In accordance with 40 CFR part 23, this regulation shall be

considered issued for the purposes of judicial review at 1 pm Eastern

time on January 15, 1997. Under section 509(b)(1) of the CWA, judicial

review of this regulation can be had only by filing a petition for

review in the United States Court of Appeals within 120 days after the

regulation is considered issued for purposes of judicial review. Under

section 509(b)(2) of the CWA, the requirements in this regulation may

not be challenged later in civil or criminal proceedings brought by EPA

to enforce these requirements.

The incorporation by reference of certain publications listed in

the regulations is approved by the Director of the Federal Register as

of January 15, 1997.

ADDRESSES: For additional engineering information contact Mr. Ronald P.

Jordan, Office of Water, Engineering and Analysis Division (4303), U.S.

Environmental Protection Agency, 401 M Street, SW, Washington, DC

20460, (202) 260-7115. For additional information on the economic

impact analyses contact Dr. Matthew Clark, Office of Water, Engineering

and Analysis Division (4303), U.S. Environmental Protection Agency, 401

M Street, SW, Washington, DC 20460, (202) 260-7192.

The complete public record for this rulemaking, including EPA's

responses to comments received during rulemaking, is available for

review at EPA's Water Docket; Room M2616, 401 M Street SW, Washington,

DC 20460. For access to Docket materials call (202) 260-3027. The

Docket staff requests that interested parties call, between 9 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.

EPA notes that many documents in the record supporting these final

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.

FOR FURTHER INFORMATION CONTACT: Charles E. White, Office of Water,

Engineering and Analysis Division (4303), U.S. Environmental Protection

Agency, 401 M Street, SW, Washington, DC 20460, (202) 260-5411.

SUPPLEMENTARY INFORMATION:

Regulated Entities

As described in the proposed rule (60 FR 9428, February 17, 1995),

EPA has clarified the definition of the Coastal Subcategory in the

Coastal Guidelines. This definition is used to describe the regulated

entities. Regulated categories and entities include:

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

Examples of regulated

Category entities

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

Industry................................. Facilities engaged in field

exploration, drilling,

production, and well

treatment in the oil and gas

industry that are in areas

defined as ``coastal'' or

that discharge into areas

defined as ``coastal.''

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

The term ``coastal'' refers to a location in or on a water of the

United States landward of the inner boundary of the territorial seas.

Note that all inland bays and wetlands are included in this definition.

In addition, any location in Texas or Louisiana between the Chapman

Line and the inner boundary of the territorial seas is defined as

``coastal.'' The Chapman Line is defined by points of latitude and

longitude within the states of Texas and Louisiana which are stated in

the rule.

The preceding table is not intended to be exhaustive, but rather

provides a guide for readers regarding entities likely to be regulated

by this action. This table lists the types of entities that EPA is now

aware could potentially be regulated by this action. Other types of

entities not listed in the table could also be regulated. To determine

whether your facility is regulated by this action, you should carefully

examine the applicability criteria Sec. 435.10 and Sec. 435.40 in the

Regulatory Text section of the rule. If you have questions regarding

the applicability of this action to a particular entity, consult the

person

[[Page 66087]]

listed in the preceding FOR FURTHER INFORMATION CONTACT section.

Alternative Baseline for Impact and Benefits Analyses

Subsequent to the issuance of general permits requiring zero

discharge for coastal facilities along the Gulf of Mexico, EPA received

individual permit applications from Texas dischargers seeking to

discharge produced water. Additionally, the U.S. Department of Energy

has provided the State of Louisiana with comments and analyses

suggesting a change to the Louisiana state law requiring zero discharge

of produced water to open bays by January 1997. Promulgation of this

rule requiring zero discharge in these areas would generally preclude

issuance of permits allowing discharge. Therefore, in addition to

calculating the costs, economic impacts, and pollutant removals

incremental to current permit limits, EPA has calculated an alternative

estimate of these factors using an ``alternative baseline.'' This

``alternative baseline'' assumes that zero discharge would no longer

apply to Texas dischargers seeking individual permits and Louisiana

open bay dischargers. Under this alternative baseline, this rule would

reduce discharges of conventional pollutants by 11,300,000 pounds per

year, nonconventional pollutants by 4,590,000,000 pounds per year, and

toxic pollutants by 880,000 pounds per year.

Overview

The preamble describes the legal authority, background, technical

and economic basis, and other aspects of the final regulation. The

definitions, acronyms, and abbreviations used in this notice are

defined in appendix A to the preamble. The regulatory text for

amendments to 40 CFR part 435, that implements this rulemaking, follows

the preamble.

Organization of This Document

Preamble

I. Legal Authority

II. Purpose and Summary of this Rulemaking

A. Purpose of this Rulemaking

B. Summary of the Final Coastal Guidelines

III. Background

A. Definitions of Guidelines and Standards

B. Requirements for Promulgating, Reviewing, and Revising

Guidelines and Standards

C. History of the Rulemaking

IV. Description of the Industry

V. Major Changes to the Database for the Final Regulation

A. Drilling Fluids and Drill Cuttings

B. Produced Water

VI. Summary of the Most Significant Regulatory Changes From Proposal

VII. Basis for the Final Regulation

A. Drilling Fluids, Drill Cuttings, and Dewatering Effluent

B. Produced Water and Treatment, Workover, and Completion Fluids

C. Produced Sand

D. Deck Drainage

E. Domestic Wastes

F. Sanitary Wastes

VIII. Economic Analysis

A. Introduction

B. Economic Impact Methodology

C. Summary of Costs and Economic Impacts

D. Cost-Effectiveness Analysis

IX. Non-Water Quality Environmental Impacts

A. Drilling Fluids and Cuttings

B. Produced Water and Treatment, Workover and Completion Fluids

X. Environmental Benefits Analysis

A. Introduction

B. Quantitative Estimate of Benefits

C. Description of Non-Quantified Benefits

XI. Related Acts of Congress, Executive Orders, and Agency

Initiatives

A. Pollution Prevention Act

B. Paperwork Reduction Act

C. Regulatory Flexibility Act

D. Small Business Regulatory Enforcement Fairness Act of 1996

(Submission to Congress and the General Accounting Office)

E. Unfunded Mandates Reform Act

F. Executive Order 12866 (OMB Review)

G. Common Sense Initiative

XII. Related Rulemakings

A. National Emission Standards for Hazardous Air Pollutants

B. Requirements for Injection Wells

C. Spill Prevention, Control, and Countermeasure

D. Shore Protection Act Regulations

XIII. Summary of Public Participation

XIV. 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

F. Removal Credits for Indirect Dischargers

G. Implementation for NPDES Permit Writers

XV. Background Documents

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

Used in This Document

I. Legal Authority

This final regulation establishes effluent limitations guidelines

and standards for the Coastal Subcategory of the Oil and Gas Extraction

Point Source Category under 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. The regulation is also being promulgated pursuant

to a Consent Decree entered in NRDC et al. v. Reilly, (D D.C. No. 89-

2980, January 31, 1992) and is consistent with EPA's latest Effluent

Guidelines Plan under section 304(m) of the CWA. (See 61 FR 52582,

October 7, 1996).

II. Purpose and Summary of This Rulemaking

A. Purpose of This Rulemaking

This final rule establishes 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 promulgated today apply to

discharges from the coastal oil and gas industry. 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 apply to those

facilities engaged in field exploration, development drilling,

production, and well treatment in the oil and gas industry that are in

areas defined as ``coastal'' or that discharge into areas defined as

``coastal.'' The term ``coastal'' refers to a location in or on a water

of the United States landward of the inner boundary of the territorial

seas. In addition, any location in Texas or Louisiana between the

Chapman Line and the inner boundary of the territorial seas is defined

as ``coastal.'' The Chapman Line is defined by points of latitude and

longitude within the states of Texas and Louisiana which are stated in

the rule. The final rule promulgated today is referred to as the

Coastal Guidelines throughout this preamble.

This preamble highlights key aspects of the Coastal Guidelines. The

technology descriptions and economic analyses discussed later in this

notice are presented in abbreviated form. More detailed descriptions

are included in the Development Document for Final Effluent Limitations

Guidelines and Standards for the Coastal Subcategory of the Oil and Gas

Extraction Point Source Category, referred to hereafter as the

``Coastal Development Document.'' EPA's economic impact assessment is

presented in detail in the Economic Impact Analysis of Final Effluent

Limitations Guidelines and Standards for the Coastal Subcategory of the

Oil and Gas Extraction Point Source Category (hereinafter, ``EIA''),

included in the rulemaking record. EPA's complete environmental

benefits analysis is presented in the Water Quality Benefits Analysis

of Final Effluent Limitations Guidelines and Standards for the Coastal

Subcategory

[[Page 66088]]

of the Oil and Gas Extraction Point Source Category (hereinafter,

WQBA), included in the rulemaking record.

B. Summary of the Final Coastal Guidelines

This rule establishes regulations based on ``best practicable

control technology currently available'' (BPT) for one wastestream

where BPT did not previously exist, ``best conventional pollutant

control technology'' (BCT), ``new source performance standards''

(NSPS), ``best available technology economically achievable'' (BAT),

``pretreatment standards for existing sources'' (PSES), and

``pretreatment standards for new sources'' (PSNS).

Drilling fluids, drill cuttings, and dewatering effluent are

limited under BCT, BAT, NSPS, PSES, and PSNS. BCT limitations are zero

discharge, except for Cook Inlet, Alaska. In Cook Inlet, BCT

limitations prohibit discharge of free oil. For both BAT and NSPS, EPA

is establishing zero discharge limitations for drilling fluids, drill

cuttings, and dewatering effluent except for Cook Inlet. In Cook Inlet,

discharge limitations include no discharge of free oil, no discharge of

diesel oil, 1 mg/kg mercury and 3 mg/kg cadmium limitations on the

stock barite, and a toxicity limitation of 30,000 ppm SPP. For both

PSES and PSNS, EPA is establishing zero discharge limitations in all

coastal subcategory locations.

Produced water and treatment, workover, and completion fluids are

limited under BCT, BAT, NSPS, PSES, and PSNS. For BCT, EPA is

establishing limitations on the concentration of oil and grease in

produced water and treatment, workover, and completion fluids equal to

current BPT limits. The Daily Maximum limitation for oil and grease is

72 mg/l and the Monthly Average limitation is 48 mg/l. For BAT and

NSPS, EPA is establishing zero discharge limitations, except for Cook

Inlet, Alaska. In Cook Inlet, the Daily Maximum limitation for oil and

grease is 42 mg/l and the Monthly Average limitation is 29 mg/l. For

both PSES and PSNS, EPA is establishing zero discharge limitations.

For produced sand, EPA is establishing zero discharge limitations

under BPT, BCT, BAT, NSPS, PSNS, and PSES.

Deck drainage is limited under BCT, BAT, NSPS, PSES, and PSNS. For

BCT, BAT, and NSPS, EPA is establishing discharge limitations of no

free oil. For PSES and PSNS, EPA is establishing zero discharge

limitations.

Domestic waste is limited under BCT, BAT, and NSPS. For BCT, EPA is

establishing no discharge of floating solids or garbage as limitations.

For BAT, EPA is establishing no discharge of foam as the limitation.

For NSPS, EPA is establishing no discharge of floating solids, foam, or

garbage as limitations. There are no PSES and PSNS for domestic waste

under the Coastal Guidelines.

Sanitary waste is limited under BCT and NSPS. For BCT and NSPS,

sanitary waste effluents from facilities continuously manned by ten or

more persons would contain a minimum residual chlorine content of 1 mg/

l, with the chlorine level maintained as close to this concentration as

possible. Facilities continuously manned by nine or fewer persons or

only intermittently manned by any number of persons must not discharge

floating solids. EPA is establishing no BAT, PSES, or PSNS regulations

for sanitary waste under the Coastal Guidelines.

III. Background

The objective of the Clean Water Act is to ``restore and maintain

the chemical, physical, and biological integrity of the Nation's

waters''. To that end, it is the national goal that the discharge of

pollutants to the nations waters be eliminated. CWA section 101.

A. Definitions of Guidelines and Standards

To assist in achieving the objective of the CWA, EPA issues

effluent limitations guidelines, pretreatment standards, and new source

performance standards for industrial dischargers. These guidelines and

standards are summarized below:

1. Best Practicable Control Technology Currently Available (BPT)--Sec.

304(b)(1) of the CWA

BPT effluent limitations guidelines apply to discharges of

conventional, toxic, and nonconventional 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 Administrator deems appropriate. CWA section

304(b)(1)(B). Where existing performance is uniformly inadequate, BPT

may be transferred from a different subcategory or category.

2. 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).

3. 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 facilities 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,

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.

4. Best Available Demonstrated Control Technology For New Sources

(BADCT)--Sec. 306 of the CWA

NSPS are based on the best available demonstrated treatment

technology and

[[Page 66089]]

apply to all pollutants (conventional, nonconventional, and toxic). New

facilities 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.

5. 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.

6. 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 facilities the best available demonstrated

technologies. EPA considers the same factors in promulgating PSNS as it

considers in promulgating NSPS.

B. Requirements for Promulgating, Reviewing, and Revising Guidelines

and Standards

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 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 proposed Effluent Guidelines Plan was published in the Federal

Register on October 7, 1996 (61 FR 52582).

C. History of the Rulemaking

EPA promulgated BPT effluent limitations guidelines for all

subcategories under the oil and gas point source category on April 13,

1979 (44 FR 22069). Since then, EPA published a notice of information

and request for comments on the coastal subcategory on November 8, 1989

(54 FR 46919) and published the proposed Coastal Guidelines on February

17, 1995 (60 FR 9428).

IV. Description of the Industry

Coastal oil and gas activities include field exploration, drilling,

production, and well treatment. Coastal activities are located on

waters of the United States 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 waters of the U.S. even in all inland

states, EPA knows of no existing operations other than those in certain

states bordering the coast. The definition also includes certain wells

in Texas and Louisiana between the ``Chapman Line'' and the inner

boundary of the territorial seas as coastal. Thus, at this time, the

coastal oil and gas operations are located only in coastal states.

Table 1 summarizes the number of producing wells and annual drilling

activities for the coastal subcategory.

Table 1.--Profile of Coastal Oil and Gas Industry

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

Number of Number of

Coastal location Region producing wells production Annual drilling

(1992) facilities (1992) activity (wells)

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

Gulf of Mexico............... Texas and Louisiana.. 4675 853 686

Alabama and Florida.. 56 \1\ ND 7

Alaska....................... Cook Inlet........... 237 8 9

North Slope.......... 2085 12 161

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

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

Total.................... ..................... 7639 877 870

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

\1\ Not determined.

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 discharged and quantity of

pollutants.

Discharges from coastal oil and gas operations in states along the

Gulf of

[[Page 66090]]

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.

A more detailed description of the industry is included in the

Coastal Development Document, contained in the record for this rule.

V. Major Changes to the Database for the Final Regulation

This section describes several of the most significant changes

which have occurred since proposal to the methodology and data base

used to calculate compliance costs, pollutant reductions, and non-water

quality environmental impacts. Other changes and issues are discussed

in other sections of the preamble, the Development Document, the

Economic Impact Analysis, the environmental benefits analysis

documents, and the record for this rule.

A. Drilling Fluids and Drill Cuttings

The compliance costs and pollutant removals presented in the

Development Document for the proposed rule have been revised to reflect

information received from coastal industry operators in response to the

proposal. As in the analysis for the proposal, drilling waste

compliance cost and pollutant reductions calculations apply only to

operations in Cook Inlet, Alaska because the rest of the coastal

subcategory is already attaining zero discharge. Since proposal, the

industry profile in Cook Inlet has changed, increasing the total waste

volume on which costs and removals are based by about 15 percent. In

addition, industry-supplied information resulted in changes to

particular cost items within the zero discharge analysis.

1. Drilling Projections

EPA's profile of future drilling activity in Cook Inlet is based on

information submitted by Cook Inlet operators. In the Development

Document for the proposal, EPA identified one operator in the analysis

which had recently canceled plans to drill six new wells. This

information about the cancellation was received too late to allow for

revision of the analysis prior to proposal. EPA has since proposal

confirmed that the operator does not intend to drill these wells and

they are not included in the revised cost and pollutant reductions

analyses for the final rule. EPA received other information in comments

on the proposal updating the drilling plans for other operators in Cook

Inlet. Compared to the profile used for the proposal, the total number

of new wells at existing platforms anticipated during the seven years

following promulgation increased by four and the total number of

platforms with drilling schedules decreased by two.

2. Engineering Costs

As was done for the proposal, EPA evaluated two disposal

technologies for complying with a zero discharge limitation for

drilling fluids and drill cuttings: 1) transport to shore for land

disposal; and 2) grinding of the drilling wastes followed by injection

in a dedicated disposal well. At proposal, compliance costs were based

on an assumption that both land disposal and downhole injection were

available technologies for all drilling locations in Cook Inlet. Costs

for both compliance technologies were developed for each operator and

the lowest cost compliance scenario was selected as the likely cost of

the proposed rule. As a result, costs for two operators were based on

disposal by injection. In response to comments disputing the

feasibility of injecting drilling wastes into the geologic formations

present in Cook Inlet, EPA reviewed information in the record and

sought additional information on this issue from industry and State and

Federal authorities. Based on the limited data available to date, EPA

believes that the information in the record indicates that certain

sites in Cook Inlet may not be able to inject sufficient volumes of

drilling wastes to enable compliance with zero discharge as EPA has

defined the technology. See the Development Document and section VII of

the preamble for additional information. For the final rule, EPA has

based zero discharge compliance costs for all operators on disposal of

the drilling wastes at landfills. This is because EPA is unable at this

time, with the limited data available, to estimate the degree to which

injection would be available in Cook Inlet.

The costing methodologies for the landfill and injection scenarios

in the final rule are based, in general, on the costing methodologies

presented in the proposal. However, EPA improved the database and

sought additional confirmatory data in response to comments on the

proposal. Engineering costs have been adjusted from 1992 dollars to

1995 dollars to better reflect the current cost of compliance with zero

discharge. Certain changes resulting from EPA's reevaluation of costing

assumptions have led to a revision in the cost of landfilling drilling

wastes.

In response to comments, EPA reevaluated certain assumptions

related to the use of supply boats and barges in transporting drilling

wastes to shore for disposal at landfills. These comments led to a

reassessment of platform storage space and boat capacities and resulted

in an increase in the number of boat trips required to haul the

drilling wastes.

As discussed at proposal, the sole land disposal site for drilling

wastes in Cook Inlet (referred herein as the Kustatan landfill) is a

private facility owned by two of the operators. While no regulatory

obstacles would prohibit disposing of the wastes from other operators

at the Kustatan landfill, since it is a private facility its

availability for use by third parties cannot be assured. As a result,

EPA's analysis considers the Kustatan landfill to be available for use

by only two of the operators in the region. Since no other land

disposal facilities in Alaska are believed available to the remaining

Cook Inlet operators, the analysis for the proposal based land disposal

costs for these operators on transporting the drilling wastes to a

disposal facility in Idaho. In the preamble for the proposed rule, EPA

discussed the availability of another disposal facility located in

Oregon and stated that costs using this facility were expected to be

``close to or less than the costs of using the Idaho facility.'' (See

60 FR 9442) Further review of these facilities has shown that savings

would in fact be realized using the Oregon facility and it is the

disposal site used in the final cost analysis. EPA also revised costing

estimates to address industry comments regarding specific fees

associated with disposal at the Kustatan landfill.

B. Produced Water

1. Industry Profile

a. Gulf of Mexico. For the analyses performed for the proposed

rule, EPA used information provided by industry sources and state

regulatory authorities to construct a profile of production facilities

currently discharging in coastal areas of the Gulf of Mexico. Under

regulations issued by the State of Louisiana, many facilities are

required to cease discharges of produced water. Based on the data

available to EPA at proposal, EPA estimated that there would be 216

production facilities discharging in the Gulf of Mexico by July 1996

(the original date scheduled for promulgating final Coastal

Guidelines). Shortly before the proposal was published, EPA's Region 6

published final NPDES General Permits regulating produced water and

produced sand discharges to coastal waters in Louisiana and Texas (60

FR

[[Page 66091]]

2387; January 9, 1995). These permits prohibited the discharge of any

produced water derived from coastal waters of Louisiana and Texas.

Because much of the industry covered by the proposed Coastal Guidelines

is also covered by these General Permits, the industry profile used in

the cost and economic analyses for the proposed rule overstates the

number of facilities that would be incrementally affected by the final

Coastal Guidelines. This discrepancy was noted at proposal. In the

preamble for the proposed Coastal Guidelines, EPA stated that due to

the close proximity (one month) of the timing of the publication of the

Region 6 General Permits and the proposed guidelines, the costs and

impacts of the proposed Coastal Guidelines was being presented in the

preamble as if the General Permits were not final. EPA presented

preliminary results of how the costs and impacts of the Coastal

Guidelines would be reduced when the General Permits became effective

and stated that the regulatory effects of the General Permits would be

incorporated in the analysis conducted for the final guidelines. See 60

FR 9430.

The main difference between the general permits and the Coastal

Guidelines is that the permits cover wastes generated by onshore

Stripper Subcategory wells that are not covered under the Coastal

Guidelines and the Louisiana permit does not cover produced water

derived from Offshore Subcategory wells that is discharged into a major

deltaic pass of the Mississippi River, or to the Atchafalaya River

below Morgan City including Wax Lake Outlet. Since proposal, EPA has

worked with industry sources and State regulatory authorities to

identify those facilities whose discharges are covered by the Coastal

Guidelines, but are not covered by General Permits. No facilities

discharging Offshore Subcategory produced water into the Atchafalaya

River were identified. Six production facilities with a total of eight

outfalls were identified as discharging produced water derived from

Offshore Subcategory wells into the major deltaic passes of the

Mississippi River.

As discussed in the Supplementary Information section of this

preamble, subsequent to the issuance of the general permits requiring

zero discharge in the Gulf of Mexico region, EPA received individual

permit applications from Texas dischargers seeking to discharge

produced water. Additionally, the U.S. Department of Energy (DOE) has

provided the State of Louisiana with comments and analyses suggesting a

change in the Louisiana state law requiring zero discharge of produced

water to open bays by January 1997.

Because promulgation of this rule requiring zero discharge in these

areas would preclude issuance of permits allowing discharge, EPA also

calculated an alternative estimate of the costs, economic impacts, and

pollutant removals under an ``alternative baseline.'' This

``alternative baseline'' assumes that zero discharge under the general

permits would no longer apply to Texas dischargers seeking individual

permits and Louisiana open bay dischargers. To do this, EPA reviewed

the list of facilities requesting an individual permit in Texas, 82 as

of the date of this writing, and identified the number of facilities

discharging to open bays using information developed by the State of

Louisiana for the DOE study of open bays. EPA obtained all available

information about these facilities from the states and EPA's Coastal

Questionnaire and used this information to develop estimates of the

technological availability, costs and economic achievability, non-water

quality environmental impacts, and pollutant removals achieved by zero

discharge.

b. Cook Inlet. EPA updated the profile of Cook Inlet production

facilities with current hydrocarbon and water production rates to

address information submitted by industry in comments. The profile was

also updated with current waterflood rates for use in estimating

compliance costs under the produced water zero discharge option. The

most notable changes to the Cook Inlet production profile include one

platform which resumed oil production and ceased waterflooding; two

platforms that resumed waterflooding; and one platform substantially

reduced its waterflood rate. Production and waterflood levels for the

remaining Cook Inlet facilities have not changed significantly since

1993. These profile changes are discussed in detail in the Development

Document and the record for the final rule.

2. Engineering Costs

a. Gulf of Mexico. Engineering costs have been adjusted from 1992

dollars to 1995 dollars to better reflect the current cost of

compliance with zero discharge. Other than the adjustment to 1995

dollars, no significant changes were made to compliance cost estimates

for the improved gas flotation option. The more significant changes to

the cost estimates for the zero discharge option are discussed below.

Total labor costs in the final analysis are nearly double the labor

costs estimated at proposal. The labor burden associated with operating

additional BAT/NSPS control technologies is unchanged from the analysis

for the proposed rule, but the labor rate has been revised upward based

on data from Bureau of Labor Statistics. Additional O&M costs were

added to reflect the costs of replacing the filter cartridges used to

remove solids from the produced water prior to injection.

O&M costs for injection pretreatment chemicals were revised based

on new data provided by the industry, in combination with the data used

at proposal. Chemicals are already added to the produced water at

treatment facilities and source water in waterflooding operations at

existing production locations. The treatment chemical costs included in

EPA's analysis are costs added incremental to current chemical

expenditures. In response to comments about the potential for solids

buildup causing downhole problems in injection wells, EPA reviewed the

workover data in the record. For the final rule, the frequency of

backwashing injection wells was doubled--from biennial to once

annually.

Pipeline costs have also been increased since proposal. While

reviewing comments regarding pipeline costs, EPA detected a scale up

error in the proposal analysis which led to underestimating costs.

In estimating costs, EPA also took into account facility-specific

data and comments where it showed discharges were currently capable of

meeting limits based on operation of improved gas flotation.

b. Cook Inlet. Other than to adjust costs to 1995 dollars, no

significant changes were made to Cook Inlet compliance cost estimates

for the limitations based on gas flotation. As at proposal, compliance

with zero discharge for the Cook inlet facilities is based on the

injection of produced water into production zones as part of the

ongoing waterflood operations or into dedicated disposal wells where

waterflooding operations do not exist.

In response to concerns raised in industry comments, capital costs

for installation of a centrifuge to dewater filtration backwash solids

were added to platforms assumed to inject produced water under the zero

discharge scenario. Centrifuges would be used to concentrate the solids

removed from the filtered produced water, thus allowing the liquid

portion of the backwash to be injected. The dewatered solids would then

be disposed of by transport to a landfill (as costed by EPA) or

injected into a disposal well. This disposal cost

[[Page 66092]]

is included as a new O&M cost in the analysis for the final Coastal

Guidelines.

O&M costs for treatment chemicals (e.g., scale inhibitors,

corrosion inhibitors, biocides) were revised based on industry data.

All locations that treat produced water prior to injection under the

zero discharge scenario are assumed to incur costs for treatment

chemicals. It should be noted that all facilities currently treating

produced water for discharge already add some chemicals to enhance

separation and provide protection of treatment equipment. Further, all

facilities currently waterflooding seawater also add treatment

chemicals prior to injection. The treatment chemical costs included in

EPA's estimated compliance costs are incremental to current treatment

facility and waterflooding chemical expenditures and therefore are

considered to adequately address industry concerns about chemical

addition costs resulting from injecting produced water into producing

formations.

Information in the record indicates that injection well workover

costs were underestimated at proposal. Workover costs for the final

analysis were increased based on comments from Cook Inlet operators and

a comparison to cost data for workovers in the Gulf of Mexico.

3. Pollutant Reduction Estimates

Similar to the February 1995 proposal, pollutant removals for the

different produced water regulatory options of the final rule were

determined by comparing the estimated effluent levels of pollutants

after treatment by the BAT/NSPS treatment system (improved performance

of gas flotation or reinjection) versus the effluent levels of

pollutants associated with a typical BPT treatment (gravity separation

or gas flotation).

In the proposal, EPA characterized BPT treatment in the Gulf of

Mexico using data collected from ten coastal oil and gas facilities

located in Louisiana and Texas. Comments received subsequent to the

proposal stated that the facilities included in the database do not

adequately represent the quality of produced water which has undergone

BPT-level treatment and, as a result, overestimate the pollutant

reductions associated with the BAT/NSPS control options. Several

comments also disputed the presence of certain pollutants included in

EPA's BPT characterization.

In response to these comments, EPA reassessed the characterization

of BPT-level effluent quality. Certain pollutants were dropped for the

final analysis because they are believed to have been measured as a

result of laboratory contamination or are otherwise not expected to be

present in produced water. In comparison to the total mass of

pollutants removed by the technologies evaluated in the BAT/NSPS

options, excluding these pollutants had negligible effect on the

reductions estimates. The pollutants excluded from the final analysis

and the reasons for the exclusion are discussed in the Development

Document, the Response to Comments Document, and the record.

Upon review of the data used at proposal, EPA determined that three

of the facilities making up the Ten Facility dataset should be excluded

from the BPT characterization for the final rule. These facilities had

high levels of oil and grease, in excess of that allowed to be

discharged under the BPT effluent limitations guidelines, and therefore

the pollutant levels at these facilities are not considered

representative of produced water which has been treated to a level

which would allow discharge to surface waters. (Produced water from

these facilities is disposed of through downhole injection.) EPA

believes it is appropriate to continue using the effluent data

collected from the remaining seven facilities to represent BPT-level

pollutant concentrations, even though not all of these facilities

actually discharge their produced water, since the treatment technology

at these facilities is typical of that used at the majority of coastal

facilities and the oil and grease content of the effluent for these

facilities was lower than that required to meet the existing BPT

effluent limitations. Total oil and grease measurements at these seven

facilities range from 8 mg/l to 43 mg/l. When averaged together, the

average oil and grease concentration for the seven facilities is 26.6

mg/l, in contrast to an average of 53 mg/l when using data from all ten

facilities. EPA notes that this revised calculation of the oil and

grease concentration in BPT-level effluent for the coastal subcategory

(26.6 mg/l) compares favorably to the BPT-level effluent data (25 mg/l)

collected previously for the offshore subcategory. (See Section IX of

the Development Document for Effluent Limitations Guidelines and

Standards for the Offshore Subcategory of the Oil and Gas Extraction

Point Source Category, EPA 821-R-93-003, January 1993.) The technology

basis used to develop BPT limitations for the coastal subcategory is

identical to the basis used to develop the offshore subcategory BPT

limitations. (See the Development Document for Interim Final Effluent

Limitations Guidelines and Proposed New Source Performance Standards

for the Oil and Gas Extraction Point Source Category, EPA 440/1-76/

055a, September 1976.)

EPA also took into account facility-specific data and comments

where it showed discharges were currently capable of meeting limits

based on operation of improved gas flotation in assessing pollutant

reductions estimates.

VI. Summary of the Most Significant Regulatory Changes From

Proposal

This section briefly identifies the most significant changes from

proposal. More detailed discussion of these changes, and identification

and discussion of other issues are included in other sections of this

notice, the Coastal Development Document, the Economic Impact Analysis,

and the record for this rule. The most significant changes from

proposal occurred with regards to: (1) Drilling fluids, drill cuttings,

and dewatering effluent and (2) produced water and treatment, workover,

and completion fluids.

For drilling fluids, drill cuttings, and dewatering effluent, EPA

proposed three options for both BAT and NSPS limitations. The three

options were: (1) Zero discharge of drilling fluids, drill cuttings,

and dewatering effluent except for Cook Inlet, where discharge

limitations include no discharge of free oil, no discharge of diesel

oil, 1 mg/kg mercury and 3 mg/kg cadmium limitations on the stock

barite, and a toxicity limitation of 30,000 ppm SPP; (2) Zero discharge

of drilling fluids, drill cuttings, and dewatering effluent except for

Cook Inlet, where discharge limitations include no discharge of free

oil, no discharge of diesel oil, both 1 mg/kg mercury and 3 mg/kg

cadmium limitations on the stock barite, and a toxicity limitation more

stringent than 30,000 ppm SPP; and (3) Zero discharge everywhere. For

both BAT and NSPS, option (1) has been selected for the final rule.

For produced water and treatment, workover, and completion fluids,

EPA proposed zero discharge everywhere for NSPS. For the final rule,

NSPS limitations are zero discharge except for Cook Inlet, Alaska. In

Cook Inlet, the Daily Maximum limitation for oil and grease is 42 mg/l

and the Monthly Average limitation is 29 mg/l.

[[Page 66093]]

VII. Basis for the Final Regulation

A. Drilling Fluids, Drill Cuttings, and Dewatering Effluent

1. Waste Characterization

Drilling fluids and drill cuttings are typically discharged in bulk

during episodes that occur intermittently during well drilling and at

the end of the drilling phase.

There are currently no drilling fluid or drill cuttings discharges

in any coastal area except for Alaska's Cook Inlet. Zero discharge is

generally met by a combination of landfilling and injection. On

Alaska's North Slope, while all drilling fluids and most drill cuttings

are injected, some cuttings are cleaned and used as fill material in

the construction of drill pads and roads. These fill materials require

a fill permit issued pursuant to section 404 of the CWA.

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 89,000 bbls drilling fluids and cuttings

are generated each year (bpy) in the Inlet. Pollutants present 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. Total Suspended Solids

(TSS) make up the bulk of the pollutant loadings, part of which is

comprised of the above mentioned toxic pollutants. TSS concentrations

are very high due to the nature of the wastes.

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 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.

EPA's general permits for drilling operations in Texas and

Louisiana (58 FR 49126, September 21, 1993) have limitations for the

discharge of dewatering effluent, while other parts of the nation

generally treat dewatering effluent as part of the drilling fluids

wastestream. However, results from the 1993 Coastal Oil and Gas

Questionnaire 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 and

growing smaller since the use of pits is phasing out due to state

permit conditions, environmental or land owner concern, and 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 is 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. EPA is establishing BAT, BCT, NSPS, PSES,

and PSNS limitations that would require zero discharge of drilling

fluids, drill cuttings, and dewatering effluent, except for BAT, BCT,

and NSPS in Cook Inlet, Alaska. Where zero discharge is required, EPA

would be controlling all pollutants in the wastestream.

For BAT and NSPS in Cook Inlet, discharge limitations for drilling

fluids, drill cuttings, and dewatering effluent include no discharge of

free oil, no discharge of diesel oil, 1 mg/kg mercury and 3 mg/kg

cadmium limitations on the stock barite, and a toxicity limitation of

30,000 ppm SPP.

As presented in the Coastal 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. Free oil is also

an indicator for toxic pollutants present in crude oil. 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 (PAHs) 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

toxic pollutants.

EPA is establishing BCT limitations for drilling fluids, drill

cuttings, and dewatering effluent that prohibit the discharge of free

oil (using the static sheen test) for Cook Inlet. The prohibition on

the discharge of free oil 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.

For Cook Inlet, 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, limitations on cadmium

and mercury content in barite will control toxic and nonconventional

pollutants in drilling waste discharges. This limitation directly

controls the levels of cadmium and mercury, and indirectly controls the

levels of other toxic pollutant metals. Control of other toxic

pollutant metals occurs because cleaner barite that meets the mercury

and cadmium limits has been shown 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; and the

concentration of cadmium with the concentration of arsenic, boron,

calcium, sodium, tin, titanium, and

[[Page 66094]]

zinc. (See the Coastal Development Document).

Toxicity of drilling fluids, drill cuttings, and dewatering

effluent is being regulated as a nonconventional pollutant that

controls certain toxic and nonconventional pollutants. It was 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 thus encourages the

use of low-toxicity drilling fluids and the use of low-toxicity

drilling fluid additives.

b. Pollutants Not Regulated. Where zero discharge is required, all

pollutants are controlled. 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 established in this 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 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 variety of drilling locations, it is not

feasible to set limitations on specific compounds contained in

additives or specialty chemicals. See the Coastal Development Document

for further discussion.

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 and individual permits, state requirements, or operational

preference, no drilling fluids and cuttings discharges are occurring in

the coastal waters of the Gulf coast states or California. The only

coastal operators disposing of drilling fluids and drill cuttings by

discharge 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. 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, onshore disposal of the drilling fluids and cuttings at an

approved facility, or disposal by injection where feasible. On Alaska's

North Slope, all drilling fluids and most drill cuttings are injected,

though some cuttings are cleaned for use as fill material for the

construction of drilling pads and roads. This fill activity is

regulated under section 404 of the CWA.

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. Operators in

Cook Inlet typically employ 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 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 Development Document for a detailed discussion of

each of these waste management techniques.

b. Additional Technologies Considered. EPA has evaluated an

additional method for drilling fluid, drill cuttings, and dewatering

effluent 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, drill cuttings, and

dewatering effluent into a slurry that can be injected into a dedicated

disposal well. The grinding system consists of a vibrating or rotating

ball mill which pulverizes the cuttings and creates an injectable

slurry. This comparatively contemporary technology has been

successfully demonstrated on the North Slope, and has been used to a

limited degree on the Gulf Coast. While injection has been demonstrated

in other parts of the U.S., injection has not been demonstrated in Cook

Inlet. EPA believes that the ability to inject is related to the

subsurface conditions of the receiving formations. While the geology of

the formations in areas other than Cook Inlet have been favorable to

injection of drilling fluids and drill cuttings, the record indicates

that geology amenable to grinding and injection does not appear to

occur throughout Cook Inlet.

In addition to grinding and injection, EPA has investigated the

feasibility of onshore disposal for this wastestream. For the coastal

subcategory drilling activities, in areas other than Cook Inlet,

current permits require zero discharge of drilling fluids and cuttings

or, in the case of the North Slope, zero discharge of drilling fluids,

and drill cuttings except where drill cuttings are reused as a fill

material. The fill activity is regulated under section 404 of the CWA.

On-land disposal or downhole injection sites are available in these

areas and are being utilized to comply with the zero discharge

requirement.

With respect to onshore disposal capacity, on-land disposal sites

are available to two of the Cook Inlet operators. These two operators

jointly own an oil and gas landfill disposal site on the west side of

the Inlet. Unfortunately, no on-land oil and gas waste disposal

facilities are available in Alaska to the other Cook Inlet operators

who plan to drill after promulgation of this rule. Therefore, EPA has

estimated the costs for disposing of drilling wastes at an on-land oil

and gas waste disposal site in Oregon.

Also with regard to zero discharge, EPA received information from

operators concerned that compliance with zero discharge could

significantly interfere with drilling operations. EPA has investigated

the significant logistical difficulties and operational problems

presented by storing and transporting drilling wastes in the Cook

Inlet, due to the space constraints, combined with the extensive tidal

fluctuations, strong currents, and ice formation during winter months.

Also, 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 option as described below.

In addition to zero discharge, EPA considered allowing the

discharge of the drilling fluids, drill cuttings, and dewatering

effluent in Cook Inlet providing the discharge met 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

[[Page 66095]]

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

in range of 100,000 ppm (SPP) to 1 million ppm (SPP). (The measure of

toxicity is a 96 hour test that estimates the concentration of

suspended particulate phase (SPP) from a drilling fluid that is lethal

to 50 percent of the tested organisms. See 40 CFR part 435, subpart A,

appendix 2). 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.

As discussed above, one option at proposal would have retained the

offshore limitations but required a more stringent toxicity limit. At

proposal, EPA based the more stringent toxicity limitations, in part,

on the volume of drilling wastes that could be injected or disposed of

onshore without interfering with ongoing drilling operations. The more

stringent toxicity limit would have been based on (1) the volume of

drilling wastes that could be subjected to zero discharge without

interfering with ongoing drilling operations and (2) a specified level

of toxicity selected such that no more than this volume of waste,

determined in the previous step, would exceed the specified level of

toxicity. However, as pointed out in comments on the proposal and

confirmed with further investigation, there are a number of problems

with the database that would be used to establish a more stringent

toxicity limitation. Many of the records in the database do not have

either a waste volume identified or indicate whether the drilling

fluids were discharged. Where waste volumes are reported, the methods

used to determine these volumes are not consistent and they are not

documented. It is also unclear whether the volumes and fluid systems

reported for any given well represent a complete record of the drilling

activity associated with the well. For these reasons, EPA rejected the

option of developing a more stringent toxicity limitation for the final

rule.

4. BAT and NSPS Options

For final consideration, EPA developed two options for the BAT and

NSPS level of control for drilling fluids and drill cuttings.

Limitations for the dewatering effluent are the same as those for

drilling fluids and drill cuttings.

Option 1 would require zero discharge of drilling fluids, drill

cuttings, and dewatering effluent 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. Limitations for Cook Inlet are identical to the limitations

applicable to offshore discharges in Alaska. Option 1 was developed

taking into consideration that Cook Inlet operations are unique to the

industry due to a combination of geology available for grinding and

injection, climate, transportation logistics, and structural and space

limitations that interfere with drilling operations.

Option 2 would prohibit the discharge of drilling fluids, drill

cuttings, and dewatering effluent from all coastal oil and gas drilling

operations. In Cook Inlet, this option uses onshore disposal as a basis

for complying with zero discharge of drilling fluids and drill

cuttings. Outside of Cook Inlet, this option uses a combination of

grinding and injection and onshore disposal as a basis for complying

with zero discharge of drilling fluids and drill cuttings.

a. Costs. Operators would not incur any costs under Option 1

because the requirements reflect current practice.

Costs to comply with Option 2 (zero discharge all) are attributed

only to Cook Inlet operators (North Slope operators are beneficially

reusing a portion of their drill cuttings and all other coastal

operators are already practicing zero discharge). Costs to comply with

this option are estimated to be approximately $8,200,000 annually for

the Cook Inlet operators. The basis for this cost analysis is that

drilling fluids and drill cuttings generated in Cook Inlet would be

hauled to shore for disposal. Costs for land disposal include water

vessel transportation, storage prior to transport to the disposal

facility, truck transportation to the disposal facility, and landfill

disposal costs. While it was evaluated, grinding and injection is not

used in the cost basis for Cook Inlet because, as mentioned earlier,

geology amenable to grinding and injection does not appear to occur

throughout Cook Inlet.

To determine the volume of drilling wastes requiring disposal, EPA

obtained the projected drilling schedules for the Cook Inlet operators

using information from the 1993 Coastal Oil and Gas Questionnaire and

contacts with industry. Using information about the volume of drilling

fluids and drill cuttings generated per well, and the projected amount

of drilling over the seven years following scheduled promulgation, EPA

estimates that the total amount of drilling fluids and drill cuttings

annually generated from these drilling operations will be approximately

89,000 barrels.

EPA also considered the logistical difficulties of transporting

drilling wastes in Cook Inlet as part of EPA's costing analysis of the

options. To achieve zero discharge, platforms would transport drilling

wastes to the eastern side of Cook Inlet by supply boat, then: (1)

Transfer the wastes to barges for transport to an existing landfill

facility on the west side of the Inlet or (2) load these wastes onto

trucks for transport to landfill disposal in Oregon. During periods of

extensive ice floes, the drilling wastes are stored on the east side of

the Inlet for extended periods of time.

For new sources, EPA expects that the costs of complying with NSPS

would be equal to or less than those for existing sources. Note that,

due to the high cost of installing new sources and the low expectation

of return, EPA does not expect new sources to be installed in Cook

Inlet independent of any new environmental regulations.

EPA also analyzed non-water quality environmental impacts for BAT

and NSPS. These impacts are discussed in Section IX of the preamble.

b. BAT and NSPS Option Selection. For both BAT and NSPS control of

drilling fluids, drill cuttings and dewatering effluent, EPA is

establishing zero discharge limitations, except for Cook Inlet. In Cook

Inlet, discharge limitations include no discharge of free oil, no

discharge of diesel oil, both 1 mg/kg mercury and 3 mg/kg cadmium

limitations on the stock barite, and a toxicity limitation of 30,000

ppm SPP. BAT limitations for dewatering effluent are applicable

prospectively. BAT limitations in this rule are not applicable to

discharges of dewatering effluent from reserve pits which as of the

effective date of this rule no longer receive drilling fluids and drill

cuttings. Limitations on such discharges shall be determined by the

NPDES permit issuing authority.

With regard to coastal facilities outside of Cook Inlet, zero

discharge is technically and economically achievable and has acceptable

non-water quality environmental impacts because it reflects current

industry practices under existing permit requirements.

With regard to coastal facilities in Cook Inlet, EPA rejected zero

discharge in large part because the technology of grinding and

injection has not been demonstrated to be available throughout Cook

Inlet. Drilling fluids and drill cuttings cannot be injected into

producing formations, as is sometimes the case for produced water,

because

[[Page 66096]]

they would interfere with hydrocarbon recovery. Thus, operators must

have available different formation zones with appropriate

characteristics (e.g., porosity and permeability) for injection of

drilling fluids and drill cuttings. See the Coastal Development

Document for discussion of geologic characteristics for the injection

of these drilling wastes. Unlike the coastal region along the Gulf of

Mexico or the North Slope of Alaska, where the subsurface geology is

relatively porous and formations for injection are readily available,

the geology in Cook Inlet is highly fragmented and information in the

record indicates that formations for injection may be not available

throughout Cook Inlet. EPA reviewed information where attempts to grind

and inject drilling fluids and drill cuttings failed in the Cook Inlet

area. For example, one operator attempted to operate a grinding and

injection well in the Kenai gas field failed due to downhole mechanical

failure of the injection well (1992/1993). There, the well experienced

abnormal pressure on the well annulus, necessitating shutdown of the

disposal operation. The operator also attempted annular pumping of

drilling fluids and drill cuttings in two production wells in the Ivan

River Field (onshore on the west side of Cook Inlet) where the annuli

of both wells plugged during injection. Another operator, attempting to

pump drilling waste into the annuli of exploration wells, lost the

integrity of the well.

Because not all of the drilling fluids and drill cuttings can be

injected, much of the waste would have to be land disposed. All but two

of the operators would likely have to transport their drilling fluids

and drill cuttings to a disposal facility out of state; the two other

operators privately own the only drilling waste land disposal facility

near Cook Inlet. (EPA is unaware of any other onshore disposal

facilities coming into existence, as Cook Inlet is a fairly mature

field nearing the end of its useful life. All but one of the existing

platforms were installed in the 1960s. The newest platform began

production in 1987, but production from the facility has remained well

below expectations.) Land disposal is a problem for Cook Inlet

operators, analogous to those faced by offshore operators in Alaska,

because the climate and safety conditions that exist during parts of

the year in Cook Inlet make transportation of drilling fluids and drill

cuttings particularly difficult and hazardous. The harsh climate, snow,

ice, and poor visibility from fog and snow often restrict land and sea

transportation. Also, the extensive tidal fluctuations (frequently in

excess of 30 feet), strong currents, and ice formation during winter

months in the Inlet impose severe logistical difficulties for storing

and transporting the drilling wastes. Moreover, the limited storage

space on platforms and transportation-related difficulties and delays

associated with a zero discharge limitation for all drilling wastes

would impose severe operational constraints on drilling activities.

Thus, for purposes for BAT and NSPS, EPA does not believe that land

disposal of all drilling wastes is generally available for Cook Inlet

operators.

There are non-water quality environmental impacts associated with

such transportation and land disposal. For BAT, EPA estimates that zero

discharge would result in 5,200 Barrel of Oil Equivalents (BOE) of fuel

being used annually, resulting in 36 tons or 72,000 pounds of air

emissions to move the waste from Cook Inlet to Oregon and sites near

Cook Inlet. While EPA believes the non-water quality environmental

impacts--in and of themselves--are not unacceptable, by comparison with

the operational constraints discussed above and pollutants removed by

zero discharge, 4,300 pounds of toxic pollutants annually, these non-

water quality environmental impacts weigh against requiring zero

discharge in Cook Inlet.

Again, for NSPS control of drilling fluids, drill cuttings, and

dewatering effluent, EPA is establishing zero discharge limitations,

except for Cook Inlet. In Cook Inlet, discharge limitations include no

discharge of free oil, no discharge of diesel oil, both 1 mg/kg mercury

and 3 mg/kg cadmium limitations on the stock barite, and a toxicity

limitation of 30,000 ppm SPP. Both inside and outside of Cook Inlet,

these NSPS limitations are technically and economically achievable and

has acceptable non-water quality environmental impacts because they

reflect current practice. With regard to the potential for a barrier to

entry, NSPS are equal to BAT limitations. BAT limitations have been

demonstrated to be economically achievable for existing structures.

Design and construction of pollution control equipment on new

production facilities is generally less expensive than retrofitting

existing facilities. Therefore, while the NSPS are equal to BAT

limitations, it is less costly for new structures to meet these

requirements and these costs would not inhibit development of new

sources.

5. BCT

a. BCT Cost Test Methodology. EPA establishes BCT limitations based

on a methodology which became effective August 22, 1986 (51 FR 24974,

July 9, 1986). This methodology compares the costs of conventional

pollutant removal under BCT with the cost of conventional pollutant

removal at a publicly owned treatment works (POTW). A description of

this methodology is contained in the preamble to the proposed rule (60

FR 9428, 9444) and the Coastal Development Document. If all options

fail either of the two tests, then BCT limitations must be set at a

level equal to BPT limitations.

b. BCT Costs Test Calculations and Options Selection. (i) Coastal

Subcategory Except for Cook Inlet. Because all operators throughout the

coastal subcategory, except in Cook Inlet, are currently practicing

zero discharge of drilling fluids and drill cuttings and dewatering

effluent, zero discharge was the only option considered. There is zero

cost for this limitation. Thus, EPA determined that zero discharge

passes the BCT cost tests and is the appropriate BCT limitation for

this wastestream. BCT limitations for dewatering effluent are

applicable prospectively. BCT limitations in this rule are not

applicable to discharges of dewatering effluent from reserve pits which

as of the effective date of this rule no longer receive drilling fluids

and drill cuttings. Limitations on such discharges shall be determined

by the NPDES permit issuing authority.

(ii) Cook Inlet. EPA considered two BCT options for Cook Inlet: BPT

limitations (no free oil) or zero discharge. BCT limits in the final

rule are established equal to BPT. Although zero discharge was

determined to be not available in Cook Inlet, the BCT cost test was

calculated to show whether such a limitation would have passed the cost

test. EPA determined that zero discharge limitations would not have

passed the BCT cost test. Costs, pollutant reductions, and the results

of the BCT cost test are presented in detail in the Coastal Development

Document. BCT limitations for dewatering effluent are applicable

prospectively. BCT limitations in this rule are not applicable to

discharges of dewatering effluent from reserve pits which as of the

effective date of this rule no longer receive drilling fluids and drill

cuttings. Limitations on such discharges shall be determined by the

NPDES permit issuing authority.

[[Page 66097]]

6. PSES and PSNS

Section 307 of the CWA authorizes EPA to develop pretreatment

standards for existing sources (PSES) and new sources (PSNS).

Pretreatment standards are designed to prevent the discharge of

pollutants that pass through, interfere with, or are otherwise

incompatible with the operation of POTWs. The pretreatment standards

for existing sources are to be technology based and analogous to the

best available technology economically achievable (BAT) for direct

dischargers. The pretreatment standards for new sources are to be

technology-based and analogous to the best available demonstrated

control technology used to determine NSPS for direct dischargers. New

indirect discharging facilities, like new direct discharging

facilities, have the opportunity to incorporate the best available

demonstrated technologies, including process changes, and in-plant

controls, and end-of-pipe treatment technologies. EPA determines which

pollutants to regulate in PSES and PSNS on the basis of whether or not

they pass through, interfere with, or are incompatible with the

operation of POTWs.

Based on comments, the 1993 Coastal Oil and Gas Questionnaire, and

other information reviewed as part of this rulemaking, EPA has not

identified any existing coastal oil and gas facilities which discharge

drilling fluids, drill cuttings, or dewatering effluent to POTW's, nor

are any new facilities projected to direct these wastes in such manner.

However, due to the high solids content of drilling fluids and drill

cuttings, EPA is establishing pretreatment standards for existing and

new sources equal to zero discharge because these wastes would

interfere with POTW operations. For further discussion, see the Coastal

Development Document. For PSNS, zero discharge would not cause a

barrier to entry, as further discussed in the Economic Impact Analysis.

B. Produced Water and Treatment, Workover, and Completion Fluids

At proposal, produced water was discussed and analyzed separately

from treatment, workover, and completion fluids (TWC). However, EPA

also proposed that discharge limitations for TWC be set equal to

discharge limitations for produced water. As stated at that time, based

on responses to the 1993 Coastal Oil and Gas Questionnaire and EPA's

Region 10 Discharge Monitoring Reports, the typical industry practice

is to combine produced water with treatment, workover, and completion

fluids for purposes of wastewater treatment. Because the treatment

technologies for these wastestreams are linked, EPA has combined these

wastestreams in the final rule for purposes of discussion.

1. Waste Characterization

Produced water is brought to the surface during the oil and gas

extraction process and can include: formation water extracted along

with oil and gas; injection water used for secondary oil recovery that

has broken through the formation and mixed with the extracted

hydrocarbons; and various well treatment chemicals added during the

production and oil/water separation processes. Produced water is the

highest volume waste in the coastal oil and gas industry. Depending on

the age of a well and site-specific formation characteristics, the

produced water can constitute between 2 percent and 98 percent of the

gross fluid production at a particular well. Generally, in the early

production phase of a well the produced water volume is relatively

small and the hydrocarbon production makes up the bulk of the fluid.

Over time, the formation approaches hydrocarbon depletion and the

produced water volume usually exceeds the hydrocarbon production. Based

on information received in the 1993 Coastal Oil and Gas Questionnaire,

the average produced water rate from a well is approximately 1180

barrels per day (bpd) in Cook Inlet and 270 bpd in the Gulf Coast. EPA

estimates under current permit requirements that 119 million barrels

per year (bpy) of produced water are discharged to surface waters by

the coastal oil and gas industry.

As part of this rulemaking, EPA has embarked upon a systematic

effluent sampling program to identify and quantify the pollutants

present in produced water, with an emphasis toward the identification

of listed toxic pollutants. Details of EPA's data collection activities

are presented in the Coastal Development Document. The information

collected has confirmed the presence of a number of organic and metal

toxic pollutants in produced water.

Pollutants contained in produced water discharges from facilities

in the coastal oil and gas industry with treatment systems able to meet

BPT permit limits were identified as part of EPA's sampling effort. A

summary of the data from these sampling activities is contained in the

Coastal Development Document. EPA's sampling data and the industry-

supplied Cook Inlet Study identified many organic toxic pollutants and

12 of the 13 metal toxic pollutants as being present in BPT treated

discharges of produced water following some treatment for oil and

grease (oil) removal. The toxic organics most often present in

significant amounts were benzene, naphthalene, phenol, toluene, and

ethylbenzene. In addition to the toxic pollutants, EPA identified total

suspended solids, oil and grease, and a number of nonconventional

pollutants including barium, chlorides, ammonia, magnesium, strontium

and iron present in produced water.

TWC fluids are primarily generated during production. Well

treatment and workover fluids are inserted downhole in a producing well

to increase a well's productivity or to allow safe maintenance of the

well. Completion fluids are inserted downhole after a well has been

drilled, and serve to clean the wellbore and maintain pressure prior to

production. In most operations, these fluids resurface with the

production fluids once production is initiated and can be reused,

discharged, or injected in a disposal well.

According to results obtained in the 1993 Coastal Oil and Gas

Questionnaire, EPA estimates that approximately 275,000 bbls (205,000

and 70,000 bpy of treatment/workover and completion fluids

respectively) of TWC fluids are discharged annually from coastal oil

and gas operations in Texas and Louisiana under current permit

requirements.

The composition of the discharges is highly dependent on the

fluid's purpose, but they generally consist of acids (in the case of

treatment) or weighted brines (for workover of completion). The

principal pollutant in these fluids is oil and grease ranging in

concentration from 15 to 722 mg/l. Total suspended solids, another

major constituent in these fluids, is present in concentrations ranging

from 65 to 1600 mg/l. Prominent toxic metals that exist in these wastes

include chromium, copper, lead, and zinc. Priority organics are also

present including acetone, benzene, ethylbenzene, xylene, toluene, and

naphthalene.

Under current permit requirements, EPA estimates that approximately

314,000 pounds of priority pollutants and 3,700,000 pounds of

conventional pollutants are being discharged annually into the coastal

subcategory. In addition, approximately 2.55 million pounds of

nonconventionals are being discharged including boron, calcium, cobalt,

iron, manganese, molybdenum, tin, vanadium, and yttrium.

2. Selection of Pollutant Parameters

a. Pollutants Regulated. Where zero discharge is required, all

pollutants

[[Page 66098]]

found in produced water and treatment, workover, and completion fluid

discharges are controlled. Where discharges are allowed, i.e., Cook

Inlet, EPA is regulating oil and grease under BAT as an indicator

pollutant controlling the discharge of toxic and nonconventional

pollutants. Operationally, oil and grease is measured by EPA's method

for Total Oil and Grease. Oil and grease is limited for produced water

under BCT as a conventional pollutant. BCT limits for treatment,

workover, and completion fluids prohibit the discharge of ``free oil''

as a surrogate for control over the conventional pollutant ``oil and

grease.'' No discharge of ``free oil'' is determined by the static

sheen test. EPA is prohibiting discharge of ``free oil'' as a surrogate

for control over the conventional pollutant ``oil and grease'' in

recognition of the complex nature of the oils present in drilling

fluids, including crude oil from the formation being drilled. Oil and

grease is limited under NSPS as both a conventional pollutant and as an

indicator pollutant controlling the discharge of toxic and

nonconventional pollutants.

It has been shown (see the Coastal Development Document) that oil

and grease serves as an indicator for toxic pollutants in the produced

water wastestream, including phenol, naphthalene, ethylbenzene, and

toluene. During its development of the Offshore Guidelines, EPA showed

that gas flotation technology (the technology basis for the oil and

grease limitations) removes both metals and organic compounds,

resulting in lower concentration levels in the discharge for the above

toxic pollutants (see Section IX of the Offshore Development Document).

b. Pollutants Not Regulated. For Cook Inlet, EPA evaluated the

feasibility of regulating separately each of the constituents present

in produced water and treatment, workover, and completion fluids during

the development of the Offshore Guidelines. Based on that analysis, EPA

determined for the Coastal Guidelines that it is not feasible to

regulate each pollutant individually for reasons that include the

following: (1) The variable nature of the number of constituents in the

produced water and treatment, workover, and completion fluids, (2) the

impracticality of measuring a large number of analytes, many of them at

or just above trace levels, (3) use of technologies for removal of oil

which are effective in removing many of the specific pollutants, and

(4) many of the organic pollutants are directly associated with oil and

grease because they are constituents of oil, and thus, are directly

controlled by the oil and grease limitation. See the Coastal

Development Document for more details.

3. Control and Treatment Technologies

a. Current Practice. With regards to produced water, information

collected by EPA through the 1993 Coastal Oil and Gas Questionnaire as

well as industry contacts indicate that no coastal oil and gas

facilities are discharging in Alabama, Alaska's North Slope,

California, Florida, or Mississippi. This is due to a combination of

factors including operational preference, waterflooding, and/or state

and federal requirements. The Louisiana Department of Environmental

Quality issued regulations in 1992 (LAC:33, IX, 7.708) which prohibit

discharges of produced water to fresh water areas characterized as

``upland'' after July 1, 1992. The Louisiana regulation defines

``upland'' as ``any land not normally inundated with water and that

would not, under normal circumstances, be characterized as swamp of

fresh, intermediate, brackish or saline marsh''. The regulation does,

however, allow discharges of produced water to a major deltaic pass of

the Mississippi River or to the Atchafalaya River below Morgan City.

The same regulation also requires that discharges inland of the inner

boundary of the Territorial Seas into intermediate, brackish or saline

waters must either cease discharges or comply with a specific set of

effluent limitations. These requirements must be met within a certain

time frame, as required in the regulations, but, no later than January

1997.

In addition, EPA issued general NPDES permits (60 FR 2387, January

9, 1995) for production wastes that prohibit discharges of produced

water in coastal areas of Texas and Louisiana. The permits do not,

however, apply to produced water derived from the offshore subcategory

which is discharged into a main pass of the Mississippi River or

Atchafalaya River below Morgan City. Along with the general permits,

EPA issued an Administrative Order allowing until January 1997 to

comply with the zero discharge requirement. Thus, although many coastal

oil and gas operators are currently discharging produced water, current

permit requirements and administrative orders indicate that the only

facilities projected to be discharging by January 1997 would be those

in Cook Inlet, Alaska, and six facilities discharging to a major

deltaic pass of the Mississippi River.

Subsequent to EPA's issuance of the final coastal production

permits, 82 facilities (as of the date of this writing) in Texas have

applied to EPA Region 6 for individual NPDES permits authorizing

discharge of produced water. Additionally, the U.S. Department of

Energy has provided the State of Louisiana with comments and analyses

suggesting a change in the Louisiana state law requiring zero discharge

of produced water to open bays by January 1997.

The current BPT regulations established for the coastal subcategory

limit the oil and grease content in the discharged produced water.

Existing technologies for the removal of oil and grease include gravity

separation, gas flotation, heat and/or chemical addition to assist oil-

water separation, and filtration. Methods for the discharge or disposal

of produced water from facilities in the coastal subcategory include

free fall discharge to surface waters, discharge below the water

surface, use of channels to convey the discharge to water bodies, and

injection via regulated Class II Underground Injection Control (UIC)

wells into underground formations. As an alternative, a number of

production sites transport produced water by pipeline, truck or barge

to shore facilities for disposal in UIC Class II wells. At times, this

transport consists of the gross fluid produced and the oil-water

separation takes place at the off-site facility.

While sampling data has indicated quantifiable reductions of

naphthalene, lead, and ethylbenzene by BPT treatment (i.e., by oil-

water separation technology), this data also demonstrates the presence

of significant levels of toxic pollutants remaining in the treated

effluent.

With regard to treatment, workover, and completion fluids, current

requirements for the control of discharges from these fluids include

BPT limitations prohibiting free oil. EPA's final general permits

applicable to discharges from coastal oil and gas drilling operations

in Texas and Louisiana further prohibit discharges of treatment,

workover and completion fluids to freshwater areas. Methods for

treatment and discharge or disposal include:

* Treatment and disposal along with the produced water

* Neutralization for pH control and discharge to surface waters

* Onshore disposal and/or treatment and discharge in coastal or

offshore areas.

In addition, these fluids may in some cases be reused.

b. Additional Technologies.

[[Page 66099]]

In developing the regulation, EPA evaluated several treatment

technologies for application to the produced water and treatment,

workover, and completion fluid wastestreams. These technologies were

considered for implementation at the coastal production sites and at

the shore facilities where much of the produced water is currently

treated for subsequent discharge to coastal subcategory waters.

(1) Improved Gas Flotation.

Gas flotation is a treatment process that separates low-density

solids and/or liquid particles (e.g., oil and grease) from liquid

(e.g., water) by introducing small gas (usually air) bubbles into

wastewater. As minute gas bubbles are released into the wastewater,

suspended solids or liquid particles are captured by these bubbles,

causing them to rise to the surface where they are skimmed off.

EPA considered as an option using gas flotation technology with

chemical addition as a basis for improving BPT-level performance. This

option would require all coastal discharges of produced water to comply

with oil and grease limitations of 29 mg/l monthly average and a daily

maximum of 42 mg/l. The technology basis for these limitations is

improved operating performance of gas flotation technology. EPA has

determined that gas flotation systems could be improved to increase

removal efficiencies--i.e., the amount of pollutants removed. Specific

mechanisms include proper sizing of the gas flotation unit to improve

hydraulic loading (water flow rate through the equipment), adjustment

and closer monitoring of engineering parameters such as recycle rate

and shear forces that can affect oil droplet size (the smaller the oil

droplet, the more difficult the removal), additional maintenance of

process equipment, and the addition of chemicals to the gas flotation

unit. (See Offshore Development Document Section IX.)

The addition of chemicals can be a particularly effective means of

increasing the amount of pollutants removed. Because the performance of

gas flotation is highly dependent on ``bubble-particle interaction,''

chemicals that enhance that interaction will increase pollutant

removal.

Gas flotation is a technology which has been used for many years in

treating produced water. This technology formed the basis for the BPT

regulations EPA promulgated in 1979. In developing final effluent

limitations guidelines and standards for the offshore subcategory (58

FR 12454; March 4, 1993), EPA evaluated comments and data submitted by

the industry which strongly urged EPA to select improved gas flotation

technology as the basis for BAT limits and NSPS, based on data

presented by the Offshore Operators Committee's (OOC's) 83 Platform

Composite Study. Industry further noted that chemical additives would

improve the amount of oil and grease in produced water that could be

removed. EPA thoroughly reviewed these comments and additional data,

and agreed with industry that improved gas flotation was the

appropriate technology for setting BAT limits and NSPS in the offshore

subcategory.

In establishing BAT limits and NSPS for produced water in the

Offshore Subcategory, EPA evaluated the effluent data from the

platforms in the 83 Platform Composite Study identified as using

improved gas flotation (e.g., use of gravity separators and chemical

additives). First, EPA modeled the offshore platform with ``median''

oil and grease effluent values--i.e., 50 percent of the platforms in

the database had oil and grease effluent values above (and 50 percent

below) the median of the effluent values measured at the median

platform. Based on the oil and grease measured at the median platform

after improved gas flotation treatment, and allowing for average

``within-platform'' variability, EPA set a daily maximum limit on oil

and grease at 42 mg/l, and a 30-day average of 29 mg/l as the BAT

limits and NSPS. (See 58 FR 12462, March 4, 1993.)

Since there are fewer operational constraints for coastal

facilities than there are for offshore facilities, the BAT and NSPS

limitations developed for the offshore subcategory, based on improved

gas flotation technology, are technologically achievable in the coastal

subcategory.

(2) Injection. EPA also considered using injection technology as a

basis for setting a zero discharge requirement under this rule. With

the exception of Cook Inlet, injection of produced water is widely

practiced by facilities in the coastal subcategory. Independent of this

rule, all coastal facilities in Alabama, California, Florida, and the

North Slope of Alaska are currently practicing zero discharge and, as

of January 1, 1997, EPA estimates that at least 80% to 99.9% of all

coastal facilities in Louisiana and Texas will be practicing zero

discharge. The 80% estimate is based on subtracting the sum of the 6

facilities discharging into a major deltic pass of the Mississippi, the

82 facilities discharging to Louisiana open bays, and the 82 facilities

associated with individual permit applicants in Texas from the 853

total coastal facilities estimated to exist along the Gulf of Mexico.

The 99.9% estimate is based on subtracting the number of facilities

discharging into a major deltic pass of the Mississippi from the total

number coastal facilities along the Gulf of Mexico. Additionally, using

a combination of Coastal Survey information and counts of facilities

known to be discharging, EPA estimated that 62% of coastal facilities

along the Gulf of Mexico were practicing zero discharge in 1994. For

the onshore subcategory, injection is the predominant technology used

to comply with the zero discharge 1979 BPT limitation. Injection

technology for produced water consists of injecting produced water,

under pressure, into Class II UIC wells into underground formations.

This option results in no discharge of produced water to surface

waters.

4. Other Technologies

Other technologies considered but rejected are discussed in the

Coastal Development Document.

5. Options Considered

EPA considered several options in developing BCT, BAT, NSPS, PSES

and PSNS limitations for discharges of produced water and treatment,

workover, and completion fluids by coastal facilities or in coastal

locations. The bases for these options were gas flotation, improved gas

flotation, injection, or a combination of injection and improved gas

flotation. As proposed, implementation of limitations on discharges of

offshore wastes into the coastal subcategory is accomplished by the

addition of language describing the applicability of subcategory

limitations when crossing subcategory boundaries and modification of

the applicability language for the offshore subcategory. Limitations

for the Agricultural and Wildlife Water Use Subcategory and the

reserved status of the Stripper Subcategory are not affected by changes

in the applicability language.

The three options selected for final consideration in developing

BAT and NSPS for control of produced water are listed below with

limitations associated with the options allowing discharges:

Option 1--(Zero Discharge; Except Major Deltaic Pass and Cook

Inlet Based On Improved Gas Flotation): With the exception of

facilities in Cook Inlet and facilities discharging offshore

produced water into the coastal subcategory waters of a major

deltaic pass of the Mississippi River or the Atchafalaya River below

Morgan City, all coastal oil and gas facilities and all facilities

discharging offshore produced water into coastal locations would be

prohibited from discharging produced water and treatment, workover,

and completion fluids. Coastal facilities in Cook Inlet and

facilities

[[Page 66100]]

discharging offshore produced water into a major deltaic pass would

be required to comply with oil and grease limitations of 29 mg/l

monthly average and 42 mg/l daily maximum based on improved

performance of gas flotation.

Option 2--(Zero Discharge; Except Cook Inlet Based On Improved

Gas Flotation): With the exception of coastal facilities in Cook

Inlet, all coastal oil and gas facilities would be prohibited from

discharging produced water and treatment, workover, and completion

fluids. Discharges of offshore produced water and treatment,

workover, and completion fluids would be prohibited when the wastes

are disposed in coastal locations. Coastal facilities in Cook Inlet

would be required to comply with oil and grease limitations of 29

mg/l monthly average and 42 mg/l daily maximum based on improved

performance of gas flotation.

Option 3--(Zero Discharge All): For all coastal facilities, this

option would prohibit discharges of produced water and treatment,

workover, and completion fluids based on injection. Further,

discharges of offshore produced water and treatment, workover, and

completion fluids would be prohibited in coastal locations.

For BCT, BPT and currently applicable permit limitations were

considered in addition to the three previously mentioned options for

BAT and NSPS. For produced water, BPT limitations include limitations

on oil and grease of 48 mg/l for Monthly Average and 72 mg/l for Daily

Maximum. For treatment, workover, and completion fluids, BPT

limitations include no discharge of free oil and current permits, where

applicable, prohibit the discharge of these fluids into fresh waters of

Texas and Louisiana.

For PSES and PSNS, the only option considered is zero discharge.

With regard to options presented at proposal: (1) Options for

treatment, workover, and completion fluids have been incorporated into

the options for produced water and (2) one option was added. The option

that considers allowing the discharge of offshore produced water into a

major deltaic pass of the Mississippi River was included in response to

comments. In response to comments, specific alternatives have been

developed and examined carefully for facilities currently discharging

offshore produced water into a major deltaic pass of the Mississippi

River or the Atchafalaya River below Morgan City. EPA has identified

six facilities with eight outfalls discharging offshore produced water

into a major deltaic pass of the Mississippi River and no facilities

discharging offshore produced water into the Atchafalaya River below

Morgan City.

The specific alternatives discussed above have been developed for

Cook Inlet to account for the different operational practices,

geological situations, and economic considerations that exist in Cook

Inlet.

4. BAT and NSPS Options

EPA is selecting ``Option 2--Zero discharge; Except Cook Inlet

Based On Improved Gas Flotation'' for the BAT and NSPS level of control

for produced water.

a. Rationale for Selection of BAT

(1) Coastal Subcategory (except Cook Inlet)

EPA is establishing zero discharge as BAT for the coastal

subcategory (except for Cook Inlet) because it is technically

available, economically achievable and reflects the appropriate level

of BAT control.

Zero discharge of produced water is technically available. Zero

Discharge of produced water has been required of onshore facilities

since EPA promulgated BPT regulations for the onshore subcategory of

the oil and gas industry in 1979. 40 CFR part 435, subpart C (44 FR

22069; April 13, 1979). With the exception of Cook Inlet, injection of

produced water is widely practiced by facilities in the coastal

subcategory. Independent of this rule, all coastal facilities in

Alabama, California, Florida, and the North Slope of Alaska are

currently practicing zero discharge and, as of January 1, 1997, EPA

estimates that at least 80% to 99.9% of all coastal facilities in

Louisiana and Texas will be practicing zero discharge. The 80% estimate

is based on subtracting the sum of the 6 facilities discharging into a

major deltic pass of the Mississippi, the 82 facilities discharging to

Louisiana open bays, and the 82 facilities associated with individual

permit applicants in Texas from the 853 total coastal facilities

estimated to exist along the Gulf of Mexico. The 99.9% estimate is

based on subtracting the number of facilities discharging into a major

deltic pass of the Mississippi from the total number of coastal

facilities along the Gulf of Mexico. Additionally, using a combination

of Coastal Survey information and counts of facilities known to be

discharging, EPA estimated that 62% of coastal facilities along the

Gulf of Mexico were practicing zero discharge in 1994. Some coastal

operators have voluntarily upgraded to zero discharge technologies

while other coastal operators have been subject to consent decrees

requiring zero discharge in citizen suits filed by environmental

groups. Zero discharge is available to coastal facilities in the Gulf

of Mexico region because formations appropriate for injection are

available.

In response to comments that operators discharging offshore

produced water into a major deltaic pass of the Mississippi should not

be subject to zero discharge, EPA closely examined these facilities.

However, EPA has identified no basis for providing these facilities

with limitations other than those established for the coastal

subcategory outside of Cook Inlet. Injection has been widely

demonstrated in practice as available to coastal facilities in states

along the Gulf Coast, including facilities discharging coastal produced

water that are near these facilities discharging offshore produced

water.

Zero discharge for the coastal subcategory, except Cook Inlet, is

economically achievable. As discussed below, EPA conducted the economic

analysis under two baselines, the current regulatory requirements

baseline and an alternative baseline. Under the current requirements

baseline, the only facilities outside of Cook Inlet that are incurring

costs as a result of this rule are those discharging wastes from the

offshore subcategory into a ``major deltaic pass.'' Under the

alternative baseline, facilities outside of Cook Inlet that are

incurring costs as a result of this rule includes those discharging

wastes from the offshore subcategory into a ``major deltaic pass,''

individual permit applicants in Texas, and Louisiana open bay

dischargers.

No closures are projected for the six facilities discharging to a

major deltaic pass. Major pass facilities incur costs and impacts under

both the current requirements and the alternative baselines. For major

pass operations, the lifetime production loss is expected to be up to

3.4 million total BOE, which is 0.6 percent of estimated lifetime

production from these facilities. While these losses may be significant

for these dischargers, in context of the coastal subcategory as a

whole, this production loss represents 0.3 percent of the coastal

production along the Gulf of Mexico. Employment losses in both Cook

Inlet and along the Gulf Coast are acceptable, see section VIII.

Considering this small percentage loss of BOE and profitability,

coupled with the determination of no closures, EPA believes that zero

discharge is economically achievable under the CWA.

For individual permit applicants in Texas and Louisiana open bay

dischargers, a total of up to 94 wells may be first year shut-ins under

zero discharge. Individual permit applicants in Texas and Louisiana

open bay dischargers are considered to have financial impacts only

under the alternative baseline. These wells are

[[Page 66101]]

approximately 2 percent of all Gulf of Mexico coastal wells. EPA

estimates related production losses would be approximately 12.8 million

BOE. This represents less than one percent of all Gulf coastal

production, most of which is in compliance with zero discharge

requirements. A maximum of 1 firm among the Louisiana open bay

dischargers and 3 firms among the individual permit applicants from

Texas could fail as a result of the proposed regulatory options.

However, EPA's modeling tends to overestimate economic impacts and firm

failures, since these models project that some currently operating

firms have already failed. These potential failures represent less than

one percent of all Gulf of Mexico coastal firms. EPA also did a

facility level analysis, conducted in response to facility-level

information received from Texas very late in the rulemaking, that shows

fewer wells are baseline failures and fewer wells fail due to the costs

of this rule because wells combine efforts for treatment and

production. EPA views the small percentage loss of BOE and

profitability, coupled with the determination of a small number of firm

closures, to meet the definition of economic achievability under the

CWA.

The non-water quality environmental impacts of zero discharge,

discussed in section IX, are acceptable.

(2) Cook Inlet

EPA is establishing BAT limitations based on improved gas

flotation, rather than zero discharge. EPA rejects zero discharge of

produced water because zero discharge is not economically achievable in

Cook Inlet.

EPA considered Cook Inlet separately from other areas in the

coastal subcategory because Cook Inlet is geographically isolated from

other areas in the coastal subcategory, zero discharge of produced

water would have disproportionately adverse economic impact in Cook

Inlet.

Unlike states along the Gulf Coast, only the production formation

is generally available for injection of produced water. Because of

this, zero discharge would require the additional costs associated with

piping produced water from existing production facilities to existing

waterflood injection sites.

EPA's economic analysis shows a disproportionate impact of zero

discharge on Cook Inlet as compared with the rest of the coastal

subcategory. EPA projects that zero discharge requirements for Cook

Inlet would close 1 of the 13 existing production platforms and result

in the loss of 108 jobs in the oil and gas industry in Cook Inlet. In

addition, there are severe economic impacts on two additional platforms

that were projected to fail at proposal. These disproportionate impacts

are demonstrated by a loss in net present value in Cook Inlet of 18.5

percent as compared to only 1.4 percent in the Gulf coast under the

current requirements baseline. In addition, there are disproportionate

impacts in Cook Inlet with regard to employment, where Cook Inlet

already suffers from unemployment higher than the national average and

higher than the rest of the coastal subcategory. The most recently

reported (1991) unemployment rate in Cook Inlet is 12.7 percent, as

compared with the unemployment rate in the Gulf coast of 6.2 to 6.4

percent and the national unemployment rate of about 5.2 percent). The

loss of 108 jobs that would occur in Cook Inlet from zero discharge

would raise the unemployment level in Cook Inlet 0.5 percent, to 13.2

percent. Thus, zero discharge would worsen the serious unemployment

situation that exists in Cook Inlet. Because Cook Inlet is economically

and geographically isolated and the economic effects of zero discharge

in Cook Inlet are significant and disproportionately worse than they

are in the rest of the subcategory, EPA rejects zero discharge in Cook

Inlet as not economically achievable.

Limitations based on improved gas flotation are technically and

economically achievable for Cook Inlet facilities. These limitations

are a Daily Maximum of 42 mg/l and a Monthly Average of 29 mg/l for oil

and grease. Improved gas flotation technology has been demonstrated in

the offshore subcategory where the wastestreams and physical

constraints are similar. No platform closures are expected as a result

of establishing these limitations. EPA expects the production loss over

the productive lifetime of these platforms to be approximately 2.4

million BOE, which is 0.5 percent of the estimated lifetime production

for the Inlet.

The non-water quality environmental impacts of these limitations,

discussed in section IX, are acceptable.

(3) Pollutant Reductions for the Selected Option

Assuming the current regulatory requirements baseline, the selected

BAT option for produced water and treatment, workover, and completion

fluids is expected to reduce discharges of conventional pollutants by

2,780,000 lbs. per year, nonconventional pollutants by 1,490,000,000

lbs. per year, and toxic pollutants by 228,000 lbs. per year.

Assuming the alternative baseline, the selected BAT option for

produced water and treatment, workover, and completion fluids is

expected to reduce discharges of conventional pollutants by 11,300,000

lbs. per year, nonconventional pollutants by 4,590,000,000 lbs. per

year, and toxic pollutants by 880,000 lbs. per year.

b. Rationale for Selection of NSPS

For NSPS control of produced water and treatment, workover, and

completion fluid discharges from new sources, EPA is establishing the

limitations associated with ``Option 2--Zero Discharge; Except Cook

Inlet Based On Improved Gas Flotation.'' Option 2 is economically

achievable for the reasons discussed in the economic impact analysis

and in Section VIII, below. The selected option for NSPS is equal to

the selected BAT option for produced water and treatment, workover, and

completion fluids. The BAT option has been demonstrated to be

technologically available and economically achievable for existing

structures. Design and construction of pollution control equipment on

new production facilities is generally less expensive than retrofitting

existing facilities. Therefore, while the NSPS requirements are equal

to the BAT requirement, it is less costly for new structures to meet

these requirements and these costs would not inhibit development of new

sources.

In addition, as discussed in Section IX, EPA has determined the

non-water quality environmental impacts to be acceptable for the

selected NSPS option for produced water and treatment, workover, and

completion fluids.

Zero discharge for Cook Inlet is rejected because of uncertainties

regarding the availability of geologic formations suitable for

receiving injected produced water. Information in the record indicates

that a potential new source in Cook Inlet could be unable to inject

adequate produced water volumes near the new source. As a result, the

new source would be faced with piping the produced water to a location

where suitable geology would be available. Based on information

available in the record, EPA projects that no new sources will be

developed in Cook Inlet. Nevertheless, EPA assessed the costs and

economic impacts incurred by a model new source facility under the zero

discharge scenario should conditions and future information lead to

development of new sources in Cook Inlet. For the modeled scenario, EPA

based costs on injecting produced water near the new source facility.

However, because of the uncertainties regarding availability of

formations suitable for injection, it is possible that a new source

structure would incur some

[[Page 66102]]

unknown cost for piping the produced water to a suitable injection

location. Since the location and availability of formations for any new

source in Cook Inlet are unknown, the maximum cost associated with

piping produced water from the wellhead to the nearest injection well

cannot be estimated.

5. BCT Methodology and Options Selection

The methodology to determine the appropriate technology option for

BCT limitations is previously described in the proposal and the Coastal

Development Document.

EPA evaluated the options listed in section VII.B.5 according to

the BCT cost reasonableness tests. The pollutant parameters used in

this analysis were total suspended solids and oil and grease. All

options fail the BCT cost reasonableness test. Thus, EPA establishes

BCT limitations for produced water equal to BPT. Limitations for

treatment, workover, and completion fluids are established as zero

discharge for fresh water in Texas and Louisiana and no free oil

everywhere else. This option reflects current permit requirements.

Costs for this option are zero, thus this option passes the BCT cost

test. A more detailed description of the BCT cost test for produced

water and treatment, workover, and completion fluids is described in

the Coastal Development Document. There are no non-water quality

environmental impacts associated with the BCT limitations because it is

equal to existing BPT requirements.

6. PSES and PSNS Options Selection

Based on the 1993 Coastal Oil and Gas Questionnaire and other

information reviewed as part of this rulemaking, EPA has not identified

any existing coastal oil and gas facilities which discharge produced

water or treatment, workover, and completion fluids to POTWs, nor are

any new facilities projected to direct their produced water discharge

in such manner. However, because EPA is establishing a limitation

requiring zero discharge for existing facilities, there is the

potential that some facilities may consider discharging to POTWs in

order to circumvent the BAT and/or NSPS limitations. Pretreatment

standards for produced water and treatment, workover, and completion

fluids are appropriate because EPA has identified the presence of a

number of toxic and nonconventional pollutants, many of which are

incompatible with the biological removal processes at POTWs and would

result in pass through or interference. Large concentrations of

dissolved solids in the form of various salts in the produced water

cause the discharge to POTWs to be incompatible with the biological

treatment processes because these ``brines'' can be lethal to the

organisms present in the POTW biological treatment systems. (See the

Coastal Development Document for detailed information on produced water

characterization.)

EPA is establishing pretreatment standards for existing and new

sources (PSES and PSNS, respectively) that prohibit the discharge of

produced water and treatment, workover, and completion fluids. Since

zero discharge to POTWs is the current practice in the coastal oil and

gas extraction industry, zero discharge is economically and

technologically achievable for PSES, and has no non-water quality

environmental impacts. The cost projections for both PSES and PSNS are

considered to be zero since no existing sources discharge to POTWs and

there are no known plans for new sources to be installed in locations

amenable to sewer hookup. Design and construction of pollution control

equipment on new production facilities is generally less expensive than

retrofitting existing facilities. Therefore, while the PSNS

requirements are equal to the PSES requirement, it is less costly for

new structures to meet these requirements and these costs would not

inhibit development of new sources. Non-water quality environmental

impacts would be similar to those for new sources, which EPA has found

to be acceptable. Thus, EPA has determined that pretreatment standards

for new sources that are equal to NSPS are economically achievable and

technologically available for PSNS and that the non-water quality

environmental impacts are acceptable.

C. Produced Sand

1. Waste Characterization

Produced sand consists primarily of the slurried particles that

surface from hydraulic fracturing and the accumulated formation sands

and other particles (including scale) generated during production.

Produced sand is generated during oil and gas production by the

movement of sand particles in producing reservoirs into the wellbore.

The generation of produced sand usually occurs in reservoirs comprised

of geologically young, unconsolidated sand formations. The produced

sand wastestream is considered a solid and consists primarily of sand

and clay with varying amounts of mineral scale and corrosion products.

This waste stream may also include sludges generated in the produced

water treatment system, such as tank bottoms from oil/water separators

and solids removed in filtration.

Produced sand is carried from the reservoir to the surface by the

fluids produced from the well. The well fluids stream consists of

hydrocarbons (oil or gas), water, and sand. At the surface, the

production fluids are processed to segregate the specific components.

The produced sand drops out of the fluids stream during the separation

process and accumulates at low points in equipment. Produced sand is

removed primarily during tank cleanouts. Because of its association

with the hydrocarbon stream during extraction, produced sand is

generally contaminated with crude oil or gas condensate.

Additional discussion of produced sand is presented in the Coastal

Development Document.

2. Selection of Pollutant Parameters

As proposed, EPA is establishing control of all pollutants present

in produced sand by prohibiting discharge of this wastestream.

3. Control and Treatment Technologies

No effluent limitations guidelines have been promulgated for

discharges of produced sand in the coastal subcategory. The final NPDES

permits for Texas, Louisiana, and the existing state NPDES permits for

Alabama contain a zero discharge limit for produced sand.

Data from the 1993 Coastal Oil and Gas Questionnaire indicate that

the predominant disposal method for produced sand is landfarming, with

underground injection, landfilling, and onsite storage also taking

place to some degree. Because of the cost of sand cleaning, in

conjunction with the difficulties associated with cleaning some sand

sufficiently to meet existing permit discharge limitations, operators

use onshore (onsite or offsite) or downhole disposal. In fact, only one

operator was identified in the 1993 Coastal Oil and Gas Questionnaire

as discharging produced sand in the Gulf of Mexico, but this operator

also stated that it planned to cease its discharge in the near future.

Cook Inlet operators submitted information stating that no produced

sand discharges are occurring in this area. No comments on the proposed

guidelines contained contrary information.

4. Options Considered and Rationale for Options Selection

EPA has selected zero discharge for control of produced sand.

Because

[[Page 66103]]

current practice for the coastal subcategory is zero discharge,

allowing the discharge of produced sand would not represent BAT level

control. As stated above, EPA's Coastal Oil and Gas Questionnaire

identified only one discharger of produced sand in the coastal

subcategory and that discharger reported an intent to cease

discharging. As stated above, the Region 6 NPDES permits published

January 9, 1995 prohibit all discharges of produced sand in coastal

waters of Louisiana and Texas. Because the industry practice is zero

discharge, the zero discharge limitation will result in no increased

cost to the industry.

EPA is establishing BPT, BCT, BAT and NSPS equal to zero discharge

for produced sand. Zero discharge is established as BPT because it

reflects the average of the best existing performance by facilities in

the coastal subcategory. Since BCT is established as equal to BPT,

there is no cost of BCT incremental to BPT. Therefore, this option

passes the BCT cost reasonableness tests. EPA has determined that zero

discharge reflects the BAT level of control because, as it is widely

practiced throughout the industry, it is both economically achievable

and technologically available. The selected option for NSPS is equal to

the selected BAT option for produced sand. Design and construction of

pollution control equipment on new production facilities is generally

less expensive than retrofitting existing facilities. Therefore, while

the NSPS requirements are equal to the BAT requirement, it is less

costly for new structures to meet these requirements and these costs

would not inhibit development of new sources. Zero discharge will have

no economic impacts on the industry. As zero discharge reflects current

practice, there are no incremental non-water quality environmental

impacts from this option.

The technology basis for compliance with PSES and PSNS is the same

as that for BAT and NSPS. EPA is establishing pretreatment standards

for produced sands equal to zero discharge because, like drilling

fluids and drill cuttings, their high solids content would interfere

with POTW operations. Because EPA is not aware of any coastal operators

discharging produced sand to POTWs, this requirement is not expected to

result in operators incurring costs. Zero discharge for PSNS would not

cause a barrier to entry for the same reasons as discussed above for

NSPS. There are no additional non-water quality environmental impacts

associated with this requirement because it reflects current practice.

D. Deck Drainage

1. Waste Characterization

Deck drainage consists of contaminated site and equipment runoff

due to storm events and wastewater resulting from spills, drip pans, or

washdown/cleaning operations, including washwater used to clean working

areas. Deck drainage is generated during both the drilling and

production phases of oil and gas operations. Currently, approximately

11.5 million barrels per year of deck drainage are discharged by

facilities in the coastal subcategory. EPA estimates that 112,000

pounds of oil and grease are discharged in this wastestream annually.

In addition to oil, various other chemicals used in drilling and

production operations may be present in deck drainage. Limited treated

effluent data are available for this wastestream, however, EPA has

identified the presence of organic and metal toxic pollutants in deck

drainage. EPA's analytical data for deck drainage comes from the data

acquired during the development of the Offshore Guidelines. EPA

conducted a three facility sampling program (described in Section V of

the Offshore Development Document) during which samples were taken of

untreated deck drainage. Eight of the toxic metals were detected, most

notably lead (ranging in concentration from 25--352 ug/l) and zinc

(ranging in concentration from 2970--6980 ug/l). Priority organics were

also present including benzene, xylene, naphthalene and toluene. Other

nonconventional pollutants found in deck drainage include aluminum,

barium, iron, manganese, magnesium and titanium.

The content and concentrations of pollutants in deck drainage can

also depend on chemicals used and stored at the oil and gas facility.

An additional study on deck drainage from Cook Inlet platforms,

reviewed during development of the Offshore Guidelines and this rule,

showed that discharges from this wastestream may also include

paraffins, sodium hydroxide, ethylene glycol, methanol and isopropyl

alcohol.

2. Selection of Pollutant Parameters

EPA has selected free oil as the pollutant parameter for control of

deck drainage. The specific conventional, toxic and nonconventional

pollutants found to be present in deck drainage are those primarily

associated with oil, with the conventional pollutant oil and grease

being the primary constituent. In addition, other chemicals used in the

drilling and production activities and stored on the structures have

the potential to be found in deck drainage. EPA believes that an oil

and grease limitation together with incorporation of site specific Best

Management Practices, as required under the stormwater program and as

discussed below, will control the pollutants in this wastestream.

The specific conventional, toxic, and nonconventional pollutants

controlled by the prohibition on the discharges of free oil are the

conventional pollutant oil and grease and the constituents of oil that

are toxic and nonconventional. Free oil is also an indicator for toxic

pollutants present in crude oil. These pollutants include benzene,

toluene, ethylbenzene, naphthalene, phenanthrene, and phenol. EPA has

determined that it is not technically feasible to control these toxic

pollutants specifically, and that the limitation on free oil in deck

drainage reflects control of these toxic pollutants at the BAT and

BADCT (NSPS) levels.

3. Control and Treatment Technologies

a. Current Practice. BPT limitations for deck drainage prohibit the

discharge of free oil. All equipment and deck space exposed to

stormwater or washwater are surrounded with berms or collars. These

berms capture the deck drainage where it flows through a drainage

system leading to a sump tank. Initial oil/water separation takes place

in the sump tank which is generally located beneath the deck floor or

underground at land-based operations. Effluent from the sump tank may

be directed to a skim pile, where additional oil/water separation

occurs. (The skim pile is essentially a vertical bottomless pipe with

internal baffles to collect the separated oil.)

The deck drainage treatment system is a gravity flow process, and

the treatment tanks generally do not require a power source for

operation. Thus, deck drainage generated at operations located in

powerless, remote situations, (such as satellite wellheads) can be

effectively treated.

It is sometimes difficult to obtain an appropriate sample of deck

drainage effluent, due to a submerged location. This precludes the use

of the static sheen test for this wastestream. Thus, free oil is

measured by the visual sheen test. Deck drainage treatment is discussed

in more detail in the Coastal Development Document.

b. Additional Technologies Considered. At proposal, EPA considered

commingling deck drainage with produced water or drilling fluids and

requiring best management practices. Deck drainage could in some

circumstances be commingled with either produced water or drill fluids

and

[[Page 66104]]

thus, could become subject to the limitations imposed on these major

wastestreams. EPA also considered requiring best management practices

(BMPs) on either a site-specific basis or as part of the Coastal

Guidelines. However, for the final rule, both of these proposed options

have been rejected. The commingling of deck drainage with produced

water or drilling fluids is not a demonstrated technology, as discussed

below. Promulgating BMPs in this rule would be redundant to the

requirements of the ``Final National Pollutant Discharge Elimination

System Storm Water Multi-Sector General Permit for Industrial

Activities'' (60 FR 50804, September 29, 1995).

With regard to commingling with produced water, the 1993 Coastal

Oil and Gas Questionnaire as well as the industry site visits reveal

that deck drainage is sometimes commingled with produced waters prior

to discharge or injection. Because of this practice, EPA investigated

an option requiring capture of the ``first flush'', or most

contaminated portion of, deck drainage. Depending on whether the deck

drainage is generated from drilling or production (actual hydrocarbon

extraction) operations, this first flush would be subject to the same

limitations as would be imposed on either produced water or drilling

fluids and drill cuttings based on the assumption that these two

wastestreams could be commingled.

EPA has rejected the first flush option for control of deck

drainage for several reasons primarily relating to whether this option

is technically available to operators throughout the coastal

subcategory. Deck drainage is currently captured by drains and flows

via gravity to separation tanks below the deck floor. However, the

problems associated with capture and treatment beyond gravity feed,

power independent systems, are compounded by the possibilities of back-

to-back storms which may cause first flush overflows from an already

full 500 bbl tank. In addition, tanks the size of 500 barrels are too

large to be placed under deck floors. Installation of a 500 bbl tank

would require construction of additional platform space, and the

installation of large pumps capable of pumping sudden and sometimes

large flows from a drainage collection system up into the tank. The

additional deck space would add significantly, especially for water-

based facilities, to the cost of this option. Further, many coastal

facilities are unmanned and have no power source available to them.

Deck drainage can be channeled and treated without power under the BPT

limitations.

Capturing deck drainage at drilling operations poses additional

technical difficulties. Drilling operations on land may involve an area

of approximately 350 square feet. A ring levee is typically excavated

around the entire perimeter of a drilling operation to contain

contaminated runoff. This ring levee may have a volume of 6,000 bbls,

sufficient to contain 500 bbls of the first flush. However, collection

of these 500 bbls when 6,000 bbls may be present in the ring levee

would not effectively capture the first flush. Costs to install a

separate collection system including pumps and tanks, would add

significantly to the cost of this option.

While costs are significant, the technological difficulties

involved with adequately capturing deck drainage at coastal facilities

are the principal reason why this option was not selected for the final

rule.

EPA's final rule does not include best management practices (BMPs)

for this wastestream. EPA believes that current industry practices, in

conjunction with the requirements included in the previously mentioned

general permit for stormwater, are sufficient to minimize the

introduction of contaminants from this wastestream to the extent

possible. These stormwater requirements require an oil and gas operator

to develop and implement a site-specific storm water pollution

prevention plan consisting of a set of BMPs depending on specific

sources of pollutants at each site.

4. Options Selection

For BAT and NSPS, EPA is establishing a limitation of no free oil.

Since free oil discharges are already prohibited under BPT, there are

no incremental compliance costs, pollutant removals, or non-water

quality environmental impacts associated with this control option.

Since this preferred option limits free oil equal to existing BPT

standards, it is technologically available and economically achievable.

EPA is establishing BCT limitations as no free oil. Since ``no free

oil'' is the BPT limitation, there is no incremental cost and this

option passes the BCT Cost Tests.

EPA is establishing PSES and PSNS limits for deck drainage as zero

discharge. EPA believes that zero discharge for PSES and PSNS is

appropriate because slugs of deck drainage would be expected to

interfere with biological treatment processes at POTWs. This is

discussed further in the Coastal Development Document.

E. Domestic Wastes

Domestic wastes result from laundries, galleys, showers, and other

similar activities. Detergents are often part of this wastestream.

Waste flows may vary from zero for intermittently manned facilities to

several thousand gallons per day for large facilities.

The conventional pollutant of concern in domestic waste is floating

solids. The BPT limitations for domestic wastes prohibit discharges of

floating solids. To comply with this limit, operators grind the waste

prior to discharge. As proposed, EPA is establishing BCT and NSPS

limitations as no floating solids. In addition, EPA is establishing BAT

and NSPS limitations to prohibit discharges of foam. Foam is a

nonconventional pollutant and its limitation is intended to control

discharges that include detergents.

As proposed, EPA is establishing discharges limitations for garbage

as included in U.S. Coast Guard regulations at 33 CFR part 151. These

regulations implement Annex V of the International Treaty to Prevent

Pollution from Ships (MARPOL) and the Act to Prevent Pollution from

Ships, 33 U.S.C. 1901 et seq. (The definition of ``garbage'' is

included in 33 CFR 151.05).

The pollutant limitations described above for domestic wastes are

all technologically available and economically achievable and reflect

the BCT, BAT and NSPS levels of control.

These limitations are technologically available because, under the

Coast Guard regulations, discharges of garbage, including plastics,

from vessels and fixed and floating platforms engaged in the

exploration, exploitation and associated offshore processing of seabed

mineral resources are prohibited with one exception. Victual waste (not

including plastics) may be discharged from fixed or floating platforms

located beyond 12 nautical miles from nearest land, if such waste is

passed through a screen with openings no greater than 25 millimeters

(approximately one inch) in diameter. Because vessels and fixed and

floating platforms must comply with these limits, EPA believes that all

coastal facilities are able to comply with this limit. While not all

coastal facilities are located on platforms, compliance with a no

garbage standard should be as achievable, if not more so, for shallow

water or land based facilities that have access to garbage collection

services. Further, the final drilling permits issued by Region 6 for

coastal Texas and Louisiana incorporates these Coast Guard regulations.

No discharge of visible foam is required by the NPDES permit for

Cook Inlet drilling. No discharge of floating solids is included in the

Region 10 BPT general permit for Cook Inlet, the Region

[[Page 66105]]

10 drilling permit, and the Region 6 general permits for coastal

operators.

These limitations are economically achievable because these BCT,

BAT and NSPS limitations for domestic waste are already included in

either existing NPDES permits or Coast Guard regulations, and therefore

these limitations will not result in any additional compliance cost.

Also, these limits and standards will have no additional non-water

quality environmental impacts. There are no incremental costs

associated with the BCT limitations; therefore, they pass the BCT cost

reasonableness tests.

Pretreatment standards are not being developed for domestic wastes

because domestic wastes are compatible with POTWs.

F. Sanitary Wastes

Sanitary wastes from coastal oil and gas facilities are comprised

of human body wastes from toilets and urinals. The volume of these

wastes vary widely with time, occupancy, and site characteristics. A

larger facility, such as an offshore platform, typically discharges

about 35 gallons of sanitary waste daily. Sanitary discharges from

coastal facilities would be expected to be less than this value since

the manning levels at most coastal facilities is less than that at

offshore locations.

The existing BPT limitation for facilities continuously manned by

10 or more people requires sanitary effluent to have a minimum residual

chlorine content of 1 mg/l, with the chlorine concentration to remain

as close to this level as possible. Facilities intermittently manned or

continuously manned by fewer than 10 people must comply with a BPT

prohibition on the discharge of floating solids. EPA Regions 6 and 4

general permits for coastal facilities also limit the discharge of TSS,

fecal coliform count, BOD and floating solids. The EPA Region 10

general permit for Cook Inlet also requires limitations for these same

parameters in addition to requirements for foam and free oil.

EPA considered zero discharge of sanitary wastes based on off-site

disposal to municipal treatment facilities or injection with other oil

and gas wastes. Off-site disposal would require pump out operations

that, while available to certain land facilities, are not easily

available to remote or water-based operations. Because sanitary wastes

are not accepted for injection into Class II wells, zero discharge

based on Class II injection was rejected for sanitary wastes.

EPA is establishing BCT and NSPS as equal to BPT limits for

sanitary waste discharges. Sanitary waste effluents from facilities

continuously manned by ten (10) or more persons must contain a minimum

residual chlorine content of 1 mg/l, with the chlorine level maintained

as close to this concentration as possible. Coastal facilities

continuously manned by nine or fewer persons or only intermittently

manned by any number of persons must comply with a prohibition on the

discharge of floating solids.

Since there are no increased control requirements beyond those

already required by BPT effluent guidelines, there are no incremental

compliance costs or non-water quality environmental impacts associated

with BCT and NSPS limitations for sanitary wastes. Since there are no

incremental costs associated with the BCT limit, it passes the BCT cost

tests.

EPA is not establishing BAT effluent limitations for the sanitary

waste stream because no toxic or nonconventional pollutants of concern

have been identified in these wastes.

Pretreatment standards are not being developed for sanitary wastes

because they are compatible with POTWs.

VIII. Economic Analysis

A. Introduction

This section describes the capital investment and annualized costs

of compliance with the Coastal Guidelines, and the potential impacts of

these compliance costs on current and future operators of coastal oil

and gas facilities. EPA's economic impact assessment is presented in

detail in the Economic Impact Analysis of Final Effluent Limitations

Guidelines and Standards for the Coastal Oil and Gas Subcategory of the

Oil and Gas Extraction Point Source Category (hereinafter, ``EIA''),

included in the rulemaking record. The EIA estimates the economic

effect of compliance costs on federal and state revenues, balance of

trade considerations, and inflation. In addition, EPA has conducted a

Regulatory Flexibility Analysis, which estimates effects on small

entities, and a cost-effectiveness analysis of all evaluated options

for (1) produced water and treatment, workover, and completion fluids

and (2) drilling fluids, drill cuttings and dewatering effluent. Except

where otherwise noted, only the results for selected options are

presented here. For all other wastestreams, EPA selected options that

would generate no costs to industry.

B. Economic Impact Methodology

This section (and, in more detail, the EIA) evaluates several

measures of economic impacts that result from compliance costs. The

economic analysis in the EIA has six major components: (1) An

assessment of the number of facilities that could be affected by this

rule; (2) an estimate of the annual aggregate (pre-tax) cost for these

facilities to comply with the rule using facility-level capital and O&M

costs; (3) use of an economic model to evaluate impacts on the

production and economic life of coastal facilities; (4) an evaluation

of impacts on firms' financial health, future oil and gas production,

Federal and State revenues, balance of trade, employment and other

secondary effects; (5) an analysis of compliance cost impacts on new

sources; and (6) an analysis of the effects on small entities.

Some of the economic impacts reported in this section are provided

in terms of present value (PV) or net present value (NPV). The NPV of

project worth is the total stream of production revenues minus all

costs and taxes over a period of years discounted back to present value

at the firm or industry borrowing rate, here 7 percent or 8 percent,

depending on the region under consideration.

All costs are reported in 1995 dollars, with the exception of cost-

effectiveness results, which, by convention, are reported in 1981

dollars. Any costs not originally in 1995 dollars have been inflated or

deflated using the Engineering News Record Construction Cost Index,

unless otherwise noted in the EIA (see EIA for details). Oil and gas

prices reported by individual operators are used where available. The

impacts reported in this analysis are based on the assumption that

these oil prices will remain constant in real terms over the time frame

of the analysis. This assumption may overestimate economic impacts, at

least over the next several years, given industry and government

forecasts showing small real price increases. Price increases would

tend to alleviate the economic impacts caused by increased compliance

costs.

The economic methodology is nearly identical to the methodology

used at proposal. Changes include adjustments to costs (noted in

Section V above), minor refinements to the financial models to more

precisely reflect tax code and accounting practices, and a change in

the baseline to which the costs of the rule are compared. The revision

to the analytical baseline represents a significant departure from the

1995 proposal analysis, although it is consistent with EPA's stated

intent at proposal to more fully incorporate the effects of recent

permit requirements in the analyses for the final rule (see 60 FR

9430). At proposal, the Region 6 General

[[Page 66106]]

Permits requiring zero discharge of produced water in Texas and

Louisiana were not yet issued. These permits apply to all coastal oil

and gas operations in Louisiana and Texas with the exception of certain

operations discharging offshore produced water into coastal waters of

the Mississippi major deltaic passes (Major Pass dischargers).

Therefore, at proposal, EPA counted compliance costs for facilities

currently covered by these permits as costs of the Coastal Guidelines.

For the final rule cost analysis, EPA has based costs on the Region

6 General Permits. As a result, EPA considers facilities' Region 6

permit compliance costs to be part of the current regulatory

requirements baseline against which the incremental costs attributable

to the Coastal Guidelines are measured. Only those facilities not

covered by the permits are considered to incur costs as a result of

this rule. The current regulatory requirements baseline analysis also

considers the effects of the revised guidelines on Cook Inlet

operators, for whom information on drilling plans and production has

been updated.

In response to comments, the Agency also has considered the effects

of the Coastal Guidelines relative to an alternative baseline, which is

based on the assumption that Louisiana Open Bay dischargers and

dischargers who have applied for individual permits in Texas might

continue to discharge under individual permits in the absence of this

rule. This alternative baseline analysis estimates effects on these

dischargers as well as the Major Pass and Cook Inlet operators.

Specific effects on the Louisiana Open Bay dischargers and Texas

Individual Permit applicants are also described as a separate part of

this alternative analysis. Data for many of these dischargers were

gathered for 1992 in the 1993 Coastal Oil and Gas Questionnaire. To

EPA's knowledge, responses to the questionnaire provide the most recent

and complete set of cost, revenue, and production data available to

date for Louisiana Open Bay and Texas Individual Permit operations. The

Texas Railroad Commission submitted data to EPA less than one week

before the date of this rule, which, because of insufficient time

remaining, could not be fully analyzed.

To model Cook Inlet and Major Pass operations, EPA used a financial

model similar to the one used to model Cook Inlet in the EIA for the

proposed rule. This model uses platforms and/or facilities (rather than

wells) as the relevant analytical units. Information for the model was

provided by the affected operators, vendors, and publicly available

documents, including information from the SEC, the Bureau of the

Census, and the Bureau of Labor Statistics. In this model, the capital

and operating costs for pollution control are added to (pre-compliance)

baseline capital and operating costs to create a post-compliance

financial scenario that evaluates the incremental effects of compliance

costs for various options. When operating costs exceed revenues, EPA

assumes that the well or facility ceases operation. EPA's model then

calculates lifetime production in barrels of oil equivalent (BOE) and

associated lifetime revenue (comprised of net income, taxes, and

royalties). The net impacts of the rule are the changes in production

and revenue from baseline to post-compliance estimates. These changes

are the primary impacts of the rule; these in turn affect employment,

firm financial health and balance of trade.

C. Summary of Costs and Economic Impacts

1. Overview of Economic Impact Analysis

The EIA focuses first on the costs and economic impacts of the

rule, assuming current permit requirements to be the baseline to which

the rule is compared. The analysis addresses costs and economic impacts

of the BAT and NSPS requirements for drilling fluids, drill cuttings

and dewatering effluent (Cook Inlet only), and for produced water and

treatment, workover and completion (TWC) wastes combined (Cook Inlet

and Major Passes). EPA's analyses are restricted to specific areas of

the Louisiana Gulf of Mexico coast and Cook Inlet, Alaska; current

permit requirements are for zero discharge in all other coastal areas.

As noted in Section VII, no significant costs will be incurred for BAT

and NSPS for other wastestreams, for which EPA is setting limits equal

to current practice. Similarly, BPT requirements established by this

rule are based on current practice and thus are expected to impose

negligible additional costs. All options for BCT requirements other

than BPT failed the BCT cost test. As a result, BCT is established

equal to BPT, with no incremental costs. PSES and PSNS requirements, as

noted in Section VII, are expected to have negligible impacts for

coastal oil and gas producers, who do not discharge to POTWs.

2. Total Costs and Impacts of the Regulation

This section presents the total costs and impacts of the BAT

limitations and NSPS established by this rule under the current

regulatory requirements baseline. Results for the alternative baseline

are presented below in Section VIII(C)(4).

EPA estimates that there are six facilities (permits), associated

with eight outfalls, that are not covered by the Region 6 permit and

that are discharging offshore produced water into one of the major

passes of the Mississippi River. There are also 13 platforms that

discharge produced water and may discharge drilling wastes into Cook

Inlet. Additionally, up to 684 existing wells and 45 new wells per year

generating TWC wastes (which are not covered by the General Permits for

produced water) would be affected by BAT and NSPS requirements,

respectively.

The six Major Pass facilities discharge some combination of coastal

and offshore produced water. EPA's evaluation of the costs and impacts

of BAT options addresses only the offshore portion of these costs,

because zero discharge of coastal waters is required by the Region 6

produced water permit.

Under the current regulatory requirements baseline, BAT limitations

for drilling fluids, drill cuttings and dewatering effluent (zero

discharge-Gulf; offshore limits-Cook Inlet) are current practice, and

thus have no incremental cost. BAT limits for produced water and TWC

fluids (zero discharge, except for Cook Inlet, where operators would

have to meet oil and grease limits based on improved gas flotation)

affect Major Pass dischargers and Cook Inlet dischargers and have total

annual compliance costs of $15.6 million (Table 2). The only NSPS costs

incurred under this rule are $600,000 annually for TWC fluids for new

wells drilled in the Gulf of Mexico.

Table 2.--Costs of Selected BAT and NSPS Options: Current Regulations

Baseline (1995)

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

Annualized

compliance costs

Wastestream ($ million/yr)

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

BAT NSPS

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

Produced Water/TWC Option 2 (BAT only).............. 15.6 ........

Drilling Fluids and Cuttings (BAT only)............. 0.00 0.00

Treatment, Workover & Completion Fluids (NSPS only). 0.00 0.6

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

a. Impacts from Best Available Technology (BAT). No firms are

expected to fail as a result of this rule under the Current Regulatory

[[Page 66107]]

Requirements baseline. Implementation of this rule is expected to cause

a reduction in national employment of 127 jobs annually, which result

from delays and reduction in oil production. EPA estimates that these

BAT limitations could reduce the NPV of affected projects' worth by up

to $63.7 million ($51.8 million from Major Pass facilities and $11.9

million from Cook Inlet), equivalent to annual impacts of $9.1 million

per year, or 1.4 percent of all coastal production's net worth. A

change in project NPV considers the effects of both compliance costs

and foregone oil and gas revenues on an oil and gas production

project's, and ultimately, on a producing company's net worth. As a

firm's net worth declines, its financial position becomes more tenuous

and the risk of failure increases (see EIA for detailed description).

Also, the BAT limitations result in $6.1 million in lost state taxes,

$8.4 million in lost royalties and $20.3 million in lost federal tax

revenues (all in present value). This represents 0.3 percent (taxes)

and 0.2 percent (royalties) of the present value of all coastal oil and

gas revenues received by states (and individuals) and 0.9 percent of

federal tax revenues from all coastal facilities.

Table 3 summarizes the BAT impacts discussed above for produced

water/TWC (the BAT impacts for drilling fluid and drill cuttings are

negligible).

Table 3.--Summary of Present Value Impacts of Selected BAT Options

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

Percent of

PV impacts coastal

Impact ($ million) industry

(percent)

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

Project NPV lost.............................. 63.7 1.4

Federal tax losses............................ 20.3 0.9

State tax losses.............................. 6.1 0.3

Lost royalties................................ 8.4 0.2

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

Total losses.............................. 98.5 ...........

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

Production losses under the selected BAT options are expected to

total at most 5.8 million barrels of oil equivalent (BOE) over the

lifetime of the wells and platforms (average post-compliance lifetime

is 10 years in Major Pass and 12 years in Cook Inlet operations). In

Cook Inlet, EPA expects the production loss over the productive

lifetimes of the platforms to be approximately 2.4 million BOE, which

is 0.5 percent of the estimated lifetime production for Cook Inlet. For

Major Pass operations, the lifetime production loss is expected to be

up to 3.4 million total BOE, which is 0.6 percent of estimated lifetime

production from these facilities. For the two regions combined, the

loss in production is 0.5 percent of total nondiscounted lifetime

production in Cook Inlet and the Major Passes, or 0.2 percent of all

Coastal oil and gas production. These losses result only from shortened

economic lifetimes; no platforms or treatment facilities are expected

to shut-in immediately due to the selected options.

The rule is not likely to have a significant affect on energy

prices, international trade, or inflation, and it would have a minimal

and indeterminate impact on national-level employment. On average, the

Major Pass facilities shut in 0.4 years earlier than they would without

the rule (in 9.9 years instead of 10.3 years). In Cook Inlet, platforms

shut in an average of 0.4 years earlier (in 12.3 years instead of 12.7

years). These impacts would have a minor effect on regional employment

because ample time is still available for workers to find alternative

employment, an effort they would need to undertake within a similar

time frame without the rule. Based on the predicted economic impacts,

EPA finds that the costs of the BAT limitations are economically

achievable for the coastal oil and gas industry.

b. Impacts from NSPS. EPA does not expect compliance with any of

the selected NSPS options to have a measurable impact on oil and gas

income, royalties or taxes. EPA estimates no costs for the NSPS

requirement for produced water in the Gulf of Mexico, because NSPS are

the same as BAT and therefore are economically achievable and pose no

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