Federal Register, Volume 61 Issue 242 (Monday, December 16, 1996)

[Federal Register Volume 61, Number 242 (Monday, December 16, 1996)]
[Rules and Regulations]
[Pages 66086-66130]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-28659]

[[Page 66085]]

_______________________________________________________________________

Part III

Environmental Protection Agency

_______________________________________________________________________

40 CFR Part 435

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

Federal Register / Vol. 61, No. 242 / Monday, December, 16, 1996 /
Rules and Regulations

[[Page 66086]]

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 435

[FRL-5648-4]
RIN 2040-AB72

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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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

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

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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
barrier to entry. EPA also estimates no cost for the NSPS requirement
for drilling wastes in the Gulf, because zero discharge represents the
current BAT requirements. Therefore, NSPS is economically achievable
and poses no barrier to entry. In the major passes, EPA estimates zero
cost for NSPS also because EPA has determined that no new sources are
planned that will discharge produced water. Costs of NSPS for TWC are
associated only with 45 new source wells per year projected in the Gulf
coastal region. Total annual NSPS compliance costs for TWC limits are
$0.6 million.
In Cook Inlet, NSPS requirements for produced water/TWC are
equivalent to BAT requirements, and are therefore economically
achievable and pose no barriers to entry. Costs for designing in
compliance equipment to new structures are typically less than those
for retrofitting the same equipment to existing operations. Based on
discussions with industry and on EPA's assessment of economic
conditions given present oil prices and production trends from Cook
Inlet's aging fields, the Agency expects no new facility (platform)
construction in Cook Inlet. Therefore, EPA estimates NSPS costs at zero
for Cook Inlet for all wastestreams. However, if potential revenue did
support the construction of a new facility in Cook Inlet, NSPS produced
water compliance costs would increase total capital costs by an
estimated 2.3 percent. This would not influence a decision to build, as
profits in Cook Inlet have a ``hurdle rate'' of somewhere around 20 to
25 percent. The hurdle rate is the estimated rate of return needed to
interest a investor in undertaking an investment. It is particularly
high in high-risk ventures such as Cook Inlet oil production. A 2.3
percent increase in capital costs would not alter the profit margin
sufficiently to discourage construction of a facility. NSPS
requirements for drilling waste are also the same as BAT requirements
and, further, add no costs and thus are economically achievable and
pose no barriers to entry. As noted above, EPA rejected zero discharge
of drilling fluids, drill cuttings and dewatering effluent for BAT in
Cook Inlet primarily for technological reasons; these reasons also
apply to NSPS.
3. Economic Impacts of Rejected Options
EPA has determined that zero discharge of all wastestreams is both
economically achievable and technically feasible in the coastal Gulf of
Mexico. As stated in Section VII, EPA rejected BAT and NSPS limitations
requiring zero discharge of produced water in Cook Inlet on the basis
that this option was not economically achievable, nor was the
combination of zero discharge of produced water and zero discharge of
drilling wastes. The economic analysis related to these decisions for
Cook Inlet is presented in the following section.
a. Produced Water. EPA rejected zero discharge of produced water in
Cook Inlet base on a finding that it was not economically achievable,
as discussed in Section VII(B)(4)(a)(2) above.
b. Drilling Fluids and Drill Cuttings. In establishing BAT
limitations and NSPS for drilling fluids, drill cuttings and dewatering
effluent in Cook Inlet, EPA rejected zero discharge primarily due to
uncertainty regarding the technical feasibility of reinjection of
drilling fluids, drill cuttings and dewatering effluent throughout the
Inlet, as well as the operational problems and non-water quality

[[Page 66108]]

environmental impacts resulting from land disposal in the area. Zero
discharge of these wastes may be particularly costly in Cook Inlet
because of the lack of suitable geological formations for injecting
drilling wastes (see Section VII). EPA estimated the annualized costs
of zero discharge of drilling fluids, drill cuttings and dewatering
effluent to be $9.2 million, based on transporting some of these wastes
to out-of-state landfills. EPA further determined that the combined
impact of zero discharge of drilling fluids, drill cuttings and
dewatering effluent and zero discharge of produced water in Cook Inlet
would result in 4 of 13 platforms closing, which EPA considers to
indicate economically unachievability.
4. Alternative Analytical Baseline
In response to comments from the Railroad Commission of Texas
(RRC), on behalf of certain Texas dischargers who have applied for
individual permits, and from the U.S. Department of Energy (DOE), on
behalf of dischargers to open bays in Louisiana, EPA considered what
the impacts of the Coastal Guidelines would be if EPA Region 6 (Texas)
or the State of Louisiana were to grant individual permits to these
dischargers allowing discharge of produced water. The RRC identified
dischargers in Texas who have applied for individual permits (74
applicants for 82 facilities at the time of this analysis) and DOE
identified 82 discharging facilities (outfalls) in Louisiana open bays
operating under 37 permits.
EPA estimated effects on Texas Individual Permit applicants and
Louisiana Open Bay operators at both the well level and at the facility
level (unlike Cook Inlet and Major Pass operators, who were analyzed
only at the facility or platform level). The well-level analysis tends
to overestimate impacts, as each well is assumed to bear costs that are
often shared by several wells served by a facility. Cost-sharing allows
lower costs per well and allows more productive wells to support less
productive ones as long as net present value is maximized. Many of the
facilities identified by RRC and DOE were already included in EPA's
Coastal Oil and Gas Questionnaire database. Costs and impacts to the
remaining facilities were modeled based on operators' reported
discharges and oil and gas production.
EPA addressed the effects of zero discharge for combined discharges
of produced water and TWC in this analysis of Texas Individual Permit
applicants and Louisiana Open Bay operators. BAT for other wastestreams
is addressed by Region 6 permits. Section VIII(C)(4)(a) addresses the
effects of zero discharge only on the Texas Individual Permit
applicants and Louisiana Open Bay facilities. Section VIII(C)(4)(b)
assesses the combined effects on these Texas and Louisiana facilities
together with costs and impacts to Major Pass and Cook Inlet
dischargers. The impacts on Major Pass dischargers under the
alternative baseline includes estimated compliance costs for zero
discharge of produced water from coastal wells. Including coastal
produced water increases Major Pass dischargers' costs by approximately
20 percent.
a. Produced Water BAT Impacts: Texas Individual Permits and
Louisiana Open Bays. Relative to the alternative baseline, EPA
estimates total annualized compliance costs for the Texas Individual
Permit and Louisiana Open Bay dischargers to attain zero discharge of
produced water to be $34.2 million. EPA estimates related production
losses would be approximately 12.8 million non-discounted BOE compared
to the baseline. This represents less than one percent of all Gulf
coastal production, most of which is already in compliance with zero
discharge requirements. These losses are associated with declines in
project NPV of up to $126.7 million, or 3.4 percent of Gulf Coastal
projects' NPV.
Production losses result from both first-year shut-ins and
shortened economic lifetimes. In the well-level analysis, a range of
284 to 400 baseline shut-ins are estimated to take place before
compliance costs are incurred, and up to 94 to 119 wells may be first
year post-compliance shut-ins under the selected options. These
baseline and first-year shut-ins are likely to be overestimates that
result from EPA's well-level modeling approach, which EPA addresses in
sensitivity analyses below and in Chapter 10 of the EIA. The 94 to 119
first year shut-in wells constitute approximately 1 to 2 percent of all
Gulf coastal wells. Based on a screening analysis, EPA identified up to
four potential firm failures, which represent less than one percent of
all Gulf of Mexico coastal firms. These results are derived from an
analysis based on well-level impacts, a conservative approach that
exaggerates both baseline and post-compliance well shut-ins.
The BAT requirements could result in a present value loss of up to
$36.7 million in federal tax revenues, or up to $5.2 million, on
average, annually (1.9 percent of federal revenues from Gulf coastal
production). Losses to state income and severance tax revenues could
total $19.8 million, or $2.8 million annually (0.9 percent of revenues
from Gulf coastal production). The states (and individuals) could also
lose royalties with an estimated present value of $25.1 million, or
$3.6 million annually (0.5 percent of revenues from Gulf coastal
production). These impacts of the Coastal Guidelines are acceptable
when compared to total federal and state tax revenues and royalties
collected from all Gulf coastal operators.
The impacts of the rule on Louisiana Open Bay dischargers and Texas
Individual Permit applicants are not expected to affect energy prices,
international trade or inflation, and would have a minimal impact on
national-level employment. Total national employment losses would be
expected to be 231 full-time equivalents (FTEs), which is approximately
2 percent of total Gulf of Mexico coastal oil and gas employment. EPA
finds that, under the assumptions of the alternative baseline, while
the economic impacts of the Coastal rule are significant to some
individual operators, they are economically achievable when compared to
the Coastal industry as a whole.
In response to late comments from the state of Texas, EPA has also
conducted a sensitivity analysis at the facility level for each and
every well identified as a baseline or first year shut-in among the
Texas individual permit applicants group, based on actual facility
level production and costs as reported by the operators of these wells.
EPA's alternative analysis shows that, in fact, when these wells are
treated as components of an entire facility, that is, where total
facility production revenues must exceed facility operating costs in
order to keep operating, most of these wells do remain open in the
baseline and do not shut in as a result of compliance. Many of the
wells do not produce much produced water (which generates compliance
costs). The production from those wells that do shut-in simply cannot
support, on a facility basis, the annual operations and maintenance
costs reported by the operators. In this alternative analysis, the one
(first year) post-compliance well shut-in that was identified in EPA's
original well-level analysis does not shut-in during the first year.
The facility level analysis shows 8 baseline shut-in wells (all in
Texas) with the Coastal rule causing 16 first year shut-ins only among
Louisiana Open Bay producers (compared to a total of 94 first year
shut-ins for both states in the well level analysis). The firm failure
analysis does not change. EPA concludes that its facility level
analysis indicates that the effect on Texas and Louisiana operators of
the

[[Page 66109]]

coastal rule will be even less significant than reported in the well-
level analysis (see Chapter 10 of EIA).

Table 4.--Economic Impacts of Produced Water/TWC Zero Discharge BAT
Options on Texas Individual Permit Applicants and Louisiana Open Bay
Dischargers
------------------------------------------------------------------------
Percent of
Present Gulf
Impact value ($ Coastal
million) subcategory
(percent)
------------------------------------------------------------------------
Project NPV lost.............................. 126.7 3.4
Federal tax losses............................ 36.7 1.9
State taxes................................... 19.8 0.9
Lost Royalties................................ 25.1 0.5
-------------------------
Total losses.............................. 208.4 1.6
------------------------------------------------------------------------

b. BAT and NSPS Impacts: Alternative Baseline Analysis. The
analysis of the alternative baseline includes all of the financial
impacts from the current regulatory requirements baseline and adds the
impacts of compliance costs on Louisiana Open Bay dischargers, Texas
Individual Permit applicants and the coastal portion of the Major Pass
dischargers. For all of these facilities--Major Passes, Cook Inlet,
Texas Individual Permit applicants and Louisiana Open Bay dischargers--
the total annual BAT and NSPS compliance costs, including produced
water, TWC, and drilling fluids, drill cuttings and dewatering effluent
options are $52.9 million relative to the alternative baseline (Table
5). Under the alternative baseline, produced water compliance costs for
Major Pass facilities increase by approximately 20 percent, compared to
the current regulatory requirements baseline, to account for the costs
of zero discharge of their coastal share of produced water.

Table 5.--Total Costs of BAT and NSPS Options ($1995)--Alternative
Baseline
------------------------------------------------------------------------
Annualized
compliance costs
Wastestream ($ million/yr)
--------------------
BAT NSPS
------------------------------------------------------------------------
Produced Water/TWC Option 2 (BAT).................. 52.3 0.00
Drilling fluids, drill cuttings and dewatering
effluent.......................................... 0.00 0.00
Treatment Workover and Completion fluids (NSPS).... 0.00 0.6
------------------------------------------------------------------------

Relative to the alternative baseline, production losses associated
with the selected BAT options are expected to be approximately 18.6
million barrels of oil equivalent (BOE) over the lifetime of the
affected wells, facilities, and platforms. This is approximately 0.6
percent of total lifetime nondiscounted production in the coastal Gulf
and Cook Inlet regions combined. Only 3 firms in Texas and one in
Louisiana would be potential failures, and a maximum of 94 wells (2% of
total coastal wells) would shut in. Most of these wells would shut in
only a few years without the rule. Declines in the net present value of
project worth would be approximately $200 million or $28 million
annually discounted over 10 years (4.4 percent of total coastal NPV).
BAT requirements could result in a present value loss of $60 million in
federal tax revenues, or $8.5 million annually (2.5 percent of federal
tax revenue from coastal operations). State income and severance tax
revenues losses associated with BAT requirements would be approximately
$26.6 million or $3.8 million annually (1.1 percent of all state tax
revenue from coastal operations). The states and other individuals
could also lose royalties totaling an estimated present value of $33.6
million, or $4.8 million annually (0.6 percent of coastal royalties).
The Coastal rule is not expected to affect energy prices,
international trade or inflation, and would have a minimal impact on
national-level employment. National level employment losses would be
expected to be approximately 375 full-time equivalents (FTEs, or annual
jobs) Table 6 summarizes the impacts discussed above.
NSPS compliance costs are the same as under the current regulatory
requirements baseline, for reasons explained above. Based on the
impacts predicted, EPA finds that the costs of the BAT limitations and
NSPS are economically achievable relative to the alternative baseline
for the Coastal Oil and Gas Industry.

Table 6.--Summary of Impacts of Selected BAT Options: Alternative
Baseline
------------------------------------------------------------------------
Percent of
Present coastal
Impact value subcategory
($million) (percent)
------------------------------------------------------------------------
Project NPV lost.............................. 200 4.4
Federal tax losses............................ 60 2.5
State taxes................................... 26.6 1.1
Lost Royalties................................ 33.6 0.6
-------------------------
Total losses.............................. 319.5 2.1
------------------------------------------------------------------------

D. Cost-Effectiveness Analysis

In addition to the foregoing analyses, EPA has conducted cost-
effectiveness analyses for all options considered by the Agency.
Results of these analyses are presented in Cost-Effectiveness Analysis
for Final Effluent Limitations Guidelines and Standards for the Coastal
Subcategory of the Oil and Gas Extraction Point Source Category, which
is included in the rulemaking record. Cost-effectiveness evaluates the
relative efficiency of options in removing toxic pollutants. Costs
evaluated include direct compliance costs, such as capital expenditures
and operations and maintenance costs.
Cost-effectiveness results are expressed in terms of the
incremental and average costs per ``pound-equivalent'' removed. A
pound-equivalent is a measure that addresses differences in the
toxicity of pollutants removed. Total pound-equivalents are derived by
taking the number of pounds of a pollutant removed and multiplying this
number by a toxic weighting factor. EPA calculates the toxic weighting
factor using ambient water quality criteria and toxicity values. The
toxic weighting factors are then standardized by relating them to a
particular pollutant, in this case copper. EPA's standard procedure is
to rank the options considered for each waste stream in order of
increasing pounds-equivalent (PE) removed. The Agency calculates
incremental cost-effectiveness as the ratio of the incremental annual
costs to the incremental pounds-equivalent removed under each option,
compared to the previous (less effective) option. Average cost-
effectiveness is calculated for each option as a ratio of total costs
to total pounds-equivalent removed. EPA reports annual costs for all
cost-effectiveness analyses in 1981 dollars, to enable limited
comparisons of the cost-effectiveness among regulated industries.
At proposal, EPA solicited comment regarding the inclusion of
indirect costs (e.g., oil and gas production-related losses) in its
analysis of cost-effectiveness. With previous effluent guidelines, EPA
has not included indirect costs associated with control technology
options in cost-effectiveness analyses. While the primary purpose of
the cost-effectiveness analysis is to compare the removal efficiencies
of technology options for a given rule, a secondary use has been to
benchmark the removal efficiency of a rule's selected option in
comparison to other effluent guidelines. Including additional costs
that were not considered in other rules makes such comparisons less

[[Page 66110]]

meaningful. In response to comment, however, in this rule, EPA
addresses cost-effectiveness in two separate analyses: first, EPA
conducts the conventional analysis, considering only direct capital and
operations and maintenance costs; and, second, EPA evaluates the cost
of lost oil/gas production in addition to direct compliance costs. The
two approaches are compared in Tables 9 and 10.
Table 7 presents the cost-effectiveness of different options
considered for produced water/TWC and drilling wastes, for the current
regulatory requirements baseline. Table 8 provides the produced water/
TWC cost-effectiveness results for the alternative baseline (the cost-
effectiveness of drilling waste options is the same in both baselines).
Table 7 shows that all considered options for produced water/TWC
wastes, including zero discharge (with an incremental cost-
effectiveness ratio of $42 per pound-equivalent) are cost-effective.

Table 7.--Cost-Effectiveness of All Options: Current Regulatory Baseline
----------------------------------------------------------------------------------------------------------------
Total annual Incremental
---------------------------------------------------- Average C- Incremental
Option Lb-Eq Cost Lb-Eq Cost E ($/Lb- C-E ($/Lb-
removed ($1981) removed ($1981) Eq) Eq)
----------------------------------------------------------------------------------------------------------------
Produced Water/TWC:
Option 1: Zero Discharge, Gulf/
Discharge Limits, Major Pass
& Cook Inlet................. 489,305 2,386,206 489,305 2,386,206 5 5
Option 2: Zero Discharge, Gulf/
Discharge Limits, Cook Inlet. 712,335 10,081,484 223,030 7,695,278 14 35
Option 3: Zero Discharge, All. 1,213,725 30,935,664 501,390 20,854,180 25 42
Drilling fluid/cuttings:
Option 1: Current limits...... 0 0 0 0 0 0
Option 2: Zero Discharge All.. 8,536 5,969,728 8,536 5,969,728 699 699
----------------------------------------------------------------------------------------------------------------

Table 8 shows that the cost-effectiveness analysis for produced
water using the alternative baseline versus the current regulatory
requirements baseline does not significantly change the outcome.
Significant additional pounds of toxics are removed to offset the
increased costs associated with using the alternative baseline.

Table 8.--Cost-Effectiveness of Produced Water/TWC Options: Alternative Baseline
----------------------------------------------------------------------------------------------------------------
Total annual Incremental
---------------------------------------------------- Average C- Incremental
Produced water/TWC option Lb-Eq Cost Lb-Eq Cost E ($/Lb- C-E ($/Lb-
removed ($1981) removed ($1981) Eq) Eq)
----------------------------------------------------------------------------------------------------------------
Option 1: Zero Discharge, Gulf/
Discharge Limits, Major Pass &
Cook Inlet....................... 1,091,754 24,502,620 1,091,754 24,502,620 22 22
Option 2: Zero Discharge, Gulf/
Discharge Limits, Cook Inlet..... 1,314,784 33,781,413 223,030 9,278,983 26 42
Option 3: Zero Discharge, All..... 1,816,174 54,635,592 501,390 20,854,180 30 42
----------------------------------------------------------------------------------------------------------------

Tables 9 and 10 present the cost-effectiveness of selected produced
water options, under both baselines, with and without the inclusion of
production losses, respectively. Incremental and average cost-
effectiveness for zero discharge of produced water under both
baselines, not including production loss costs (i.e., EPA's standard
analysis) are shown in Table 9; cost-effectiveness results for zero
discharge, including the value of production losses are shown in Table
10. The inclusion of production losses has a relatively minor effect on
the selected options' cost-effectiveness. In fact, the costs shown,
including production losses (Table 10), are somewhat less than those in
Table 9. This is because, in order to avoid double counting, EPA
assumed no compliance costs associated with baseline and first year
shut-ins and dry wells. These facilities would not incur compliance
costs if they immediately shut in. Eliminating these facilities from
the database used for compliance cost analysis results in lower total
compliance costs, even though the value of their lost production is
factored in.

Table 9.--Cost-Effectiveness of Selected Options--Direct Compliance Costs Only
----------------------------------------------------------------------------------------------------------------
Incremental
Lb-Eq Cost Average cost- cost-
Wastestream removed ($1981) effectiveness effectiveness
($/Lb-Eq) ($/Lb-Eq)
----------------------------------------------------------------------------------------------------------------
Produced Water/TWC:
Current Requirements Baseline....................... 712,335 10,081,484 14 35
Alternative Baseline................................ 1,314,784 33,781,413 26 42
----------------------------------------------------------------------------------------------------------------

[[Page 66111]]

Table 10.--Cost-Effectiveness of Selected Options--Compliance Costs and Production Losses
----------------------------------------------------------------------------------------------------------------
Incremental
Lb-Eq Cost Average cost- cost-
Wastestream removed ($1981) effectiveness effectiveness
($/Lb-Eq) ($/Lb-Eq)
----------------------------------------------------------------------------------------------------------------
Produced Water/TWC:
Current Requirements Baseline....................... 712,335 9,494,585 13 31
Alternative Baseline................................ 1,314,784 29,817,756 23 37
----------------------------------------------------------------------------------------------------------------

Based on the cost-effectiveness results shown in Tables 7 through
10, EPA has determined that the selected options are cost-effective.

IX. Non-Water Quality Environmental Impacts

The elimination or reduction of one form of pollution has the
potential to aggravate other environmental problems. Under sections
304(b) and 306 of the CWA, EPA is required to consider these non-water
quality environmental impacts (including energy requirements) in
developing effluent limitations guidelines and NSPS. In compliance with
these provisions, EPA has evaluated the effect of these regulations on
air pollution, solid waste generation and management, consumptive water
use, and energy consumption. Because the technology basis for the
limitation on drilling fluids and drill cuttings requires transporting
the wastes to shore for treatment and/or disposal, adequate onshore
disposal capacity for this waste is critical in assessing the options.
Safety, impacts of marine traffic on coastal waterways, and other
factors related to implementation were also considered. EPA evaluated
the non-water quality environmental impacts on a regional basis.
Although not specifically detailed in the discussion below, the non-
water quality environmental impacts that would be associated with
requirements on future drilling and production activities in regions
other than the Gulf of Mexico, California, and Alaska are considered
acceptable because they would be considered to be similar to the
impacts determined to be acceptable in the Gulf of Mexico, California,
and Alaska. The non-water quality environmental impacts associated with
requirements for drilling wastes and produced water are discussed
below. The limitations and standards being promulgated for the
remaining wastestreams covered by this rule will result in no
significant increases in non-water quality environmental impacts.

A. Drilling Fluids, and Cuttings

The non-water quality environmental impacts quantified for the
drilling fluids, drill cuttings, and dewatering effluent control
options are limited to the wastes generated in Cook Inlet. All other
coastal areas are currently achieving zero discharge of these wastes
and thus the control options cause no additional impacts. The control
technology basis for compliance with the drilling waste options
considered is a combination of product substitution and transportation
of drilling wastes to shore for treatment and/or disposal. It is
possible that in certain areas compliance with a zero discharge
limitation for a portion of the drilling wastes would be achieved of by
grinding followed by injection in disposal wells. However, EPA is
unable to determine the degree to which this may be possible. The non-
water quality environmental impacts associated with the treatment and
control of these wastes from new wells at existing sources are
summarized in Table 10. No new sources are expected to be developed in
Cook inlet. Therefore, no non-water quality environmental impacts are
expected to result from the NSPS requirements for drilling wastes.
EPA's methodology for calculating non-water quality environmental
impacts is generally unchanged from the proposal. (See the preamble for
the proposed rule at 60 FR 9467.) Certain assumptions related to waste
handling and disposal which affect fuel use and air emissions have been
updated. These changes are summarized in Section V of the preamble and
presented in more detail in the Coastal Development Document and the
record for the final rule.

Table 10.--Non-Water Quality Environmental Impacts for Drilling Waste
Control Options
------------------------------------------------------------------------
Air
Energy emissions
Options consumption (tons/
(BOE/year) year)
------------------------------------------------------------------------
Option 1: Zero discharge all except Cook Inlet.. 0 0
Option 2: Zero discharge all.................... 5,200 36
------------------------------------------------------------------------

B. Produced Water and Treatment, Workover and Completion Fluids

The energy requirements and air emissions calculated for produced
water control options considered for existing sources are presented in
Table 11. These non-water quality environmental impacts have been
updated since proposal to address changes in the industry profile which
have affected the volume of produced water requiring treatment and/or
disposal. The technology bases used to quantify these impacts are
improved gas flotation and subsurface injection. Detailed discussions
of the additional equipment required to comply with the control options
are included in the Coastal Development Document and the record for the
final rule. EPA's estimates of the non-water quality environmental
impacts calculated using the alternative baseline are presented in the
Coastal Development Document.
Non-water quality environmental impacts from produced water and
treatment, workover, and completion fluids NSPS accrue only from
injection of TWC fluids. This is because for produced water, NSPS
reflects current requirements, except for main pass dischargers. Thus,
in the absence of NSPS, dischargers would have to meet BAT, which is
zero discharge. There are no non-water quality environmental impacts
for produced water and TWC fluids NSPS in Cook Inlet. There are no non-
water quality environmental impacts for produced water in the main
passes of the Mississippi River or Atchafalaya River, because no new
sources are projected in these locations. Elsewhere in the Gulf, where
new

[[Page 66112]]

sources are projected, existing general permits allow discharge of TWC
fluids. Thus, EPA estimated the non-water quality environmental impacts
resulting from injection of TWC fluids at new sources. These impacts
are an increase in total air emissions by two tons per year and
approximately 190 BOE per year in additional fuel use. These air
emissions represent a small portion of the total emissions from coastal
oil and gas activities along the Gulf Coast.

Table 11.--Non-Water Quality Environmental Impacts for Produced Water
and TWC Fluids Control Options for Existing Sources
------------------------------------------------------------------------
Air
Energy emissions
Options consumption (tons/
(BOE/year) year)
------------------------------------------------------------------------
Option 1: Zero Discharge; Except Major Deltaic
Pass and Cook Inlet Based On Improved Gas
Flotation...................................... 4,800 43
Option 2: Zero Discharge; Except Cook Inlet
Based On Improved Gas Flotation................ 93,700 1,110
Option 3: Zero Discharge All.................... 188,000 1,260
------------------------------------------------------------------------

X. Environmental Benefits Analysis

A. Introduction

This section describes results of EPA's environmental benefits
analysis. EPA's complete environmental benefits analysis is presented
in the Water Quality Benefits Analysis of Final Effluent Limitation
Guidelines and Standards for the Coastal Subcategory of the Oil and Gas
Extraction Point Source Category EPA-821-R-96-024 (hereinafter, WQBA),
included in the rulemaking record. The WQBA evaluates the effect of
current discharges on the coastal environment and the benefits of the
Coastal Guidelines. Two baselines, the current requirements baseline
and the alternative baseline that are discussed in the preamble above,
are used in this analysis. In addition, this analysis parallels the
option selection discussion by distinguishing between Cook Inlet and
all other coastal locations. For purposes of the WQBA, only the two
main wastestreams (i.e., produced water and drilling fluids and drill
cuttings) are evaluated. The analysis was limited to these wastestreams
because: (1) Treatment, workover, and completion fluids are
conservatively considered to be a component of the produced water
wastestream and (2) regulatory options considered for the other
wastestreams reflect current permit requirements where applicable or
current practice.
The WQBA examines potential impacts from current produced water
discharges in both geographic areas, and from drilling fluids and drill
cuttings discharges in Cook Inlet. The effects of produced water for
other coastal areas (i.e., Florida, Alabama, Mississippi, California
and North Slope, Alaska), and drilling fluids and drill cutting
discharges in addition to the above coastal areas in Louisiana and
Texas are not evaluated because they are prohibited by state
authorities and existing NPDES permits, and EPA has issued no
individual permits allowing these discharges.
Under the current requirements baseline, this rule will require
major deltaic pass dischargers of offshore wastes (Major Pass
facilities) to meet zero discharge of produced water, and Cook Inlet
dischargers to meet new oil and grease limits for the discharge of
produced water and current limits for the discharge of drilling fluids
and drill cuttings. Under the alternative baseline, EPA investigated
the impacts of produced water discharges by Texas individual permit
applicants and Louisiana Open Bay dischargers on the coastal
environment, and the benefits of zero discharge. Two types of benefits
are analyzed: quantified (including non-monetized and monetized
benefits), and non-quantified benefits.
Coastal waters have diverse ecosystems which: act as spawning
grounds, nurseries and habitats for important estuarine and marine
species (finfish and shellfish); support highly valuable commercial and
recreational fisheries; and provide vital habitat for seabirds, shore
birds and terrestrial wildlife. A majority of commercial and
recreational shellfish (oysters, shrimps, and crabs) and many finfishes
spend significant portion of their life in bays and estuaries. Total
1994 value of commercial fisheries (including both finfish and
shellfish) $336 million for Louisiana and $207 million for Texas, for
total of $543 million. The 1995 value of Cook Inlet commercial
fisheries (finfish, and shellfish) was $51 million. The estimated Cook
Inlet recreational fishery is valued at $28 million per year (in 1995
dollars). In addition, personal use and subsistence fisheries provide a
food source to the Gulf of Mexico coastal residents and a food source
and cultural values to Alaskan residents and Alaskan native
populations. Coastal areas also serve as vital habitats for numerous
federally designated endangered and threatened species (including 32 in
coastal areas of Louisiana and Texas), and migrating waterfowl.
The coastal waters along the Gulf of Mexico are generally shallow,
where tidal action has limited effect, and dilution and dispersion are
more limited than offshore waters. Additionally, pollutants can migrate
much more readily into sediments, where they may have long residence
times. Consequently, these receiving environments are highly sensitive
to pollutant discharges compared to open offshore areas. Many of the
pollutants in coastal oil and gas discharges are either conventional
pollutants, aquatic toxicants, human carcinogens, or human systemic
toxicants. The aquatic impact of these pollutants on biota include
acute toxicity; chronic toxicity; effects on reproductive functions;
physical destruction of spawning and feeding habitats; and loss of prey
organisms. In addition, many of these pollutants are persistent,
resistant to biodegradation and accumulate in sediments and aquatic
organisms. Chemical contamination of coastal water, sediment and biota
may also directly or indirectly impact local aquatic and terrestrial
wildlife and humans consuming exposed biota.
The five major passes of the Mississippi River receiving produced
water from offshore operations differ physically in depth, river flows
and sediment types. Compared to the narrower, more energetic passes
with hard packed sand, flows in shallower, wider passes are of slower
velocity, resulting in more organic bottom deposits and thus supporting
more organic life. All these passes are important nursery grounds for
both saltwater and freshwater organisms and support recreational and
commercial fishery. The deltaic region of the Mississippi River ranks
in the top 10% for productivity of all United States wetland estuaries.
This region also includes the Delta National Wildlife Refuge (NWR) and
the Pass a Loutre State Fish and Game Preserve (SFGP), which in turn
support one of the largest wading bird rookeries in the United States
and hundreds of thousands of wintering waterfowl. Three major passes
receiving offshore produced water are connected to this region. Raphael
Pass winds directly through Delta NWR, while Emeline Pass establishes
the northern border of this refuge. North Pass is included as part of
the northern border of Pass a Loutre SFGP.
Compared to the Gulf of Mexico region, Cook Inlet is an extremely

[[Page 66113]]

dynamic tidal estuarine system and its physical characteristics
influence the fate and transport of contaminants in its waters. Water
movement in Cook Inlet is dominated by the tidal cycle and strongly
influenced by the freshwater inputs from rivers and precipitation.
Benefits of Coastal Guidelines include elimination or reduction of
toxic, conventional, and nonconventional pollutants, and elimination or
reduction of impacts on human health and aquatic life. Potential
benefits may ultimately include reduction of discharge-related aquatic
habitat degradation; improved recreational fisheries; improved
subsistence and personal use fisheries (potentially important to low-
income anglers and Alaska's Native anglers, etc.); improved commercial
fisheries; improved aesthetic quality of waters; improved recreational
opportunities; and decreased harm to threatened or endangered species
in the Gulf of Mexico and Cook Inlet.
Under the current requirements baseline, the Coastal Guidelines
would eliminate total of about 1.5 billion pounds of pollutants to the
coastal receiving waters of states adjacent to the Gulf of Mexico and
to Alaskan waters. Under the alternative baseline, the Coastal
Guidelines would eliminate total of 4.6 billion pounds of conventional,
toxic and nonconventional pollutants (including Gulf of Mexico and Cook
Inlet) (see Table 12).

Table 12.--Pollutants Removed by Current Permit Requirements and Alternative Baselines
--------------------------------------------------------------------------------------------------------------------------------------------------------
Removals under the current requirements baseline \1\ Additional removals under the alternative
---------------------------------------------------------- baseline
Produced water Drilling -----------------------------------------------
Pollutants removed by coastal guidelines (lbs/ ----------------------------- fluids and Produced water
year) cuttings Total (lbs/ --------------------------------
Major deltaic ------------- year) Louisiana open Total (lbs/
passes Cook Inlet bay Texas permit year) \2\
Cook Inlet dischargers applicants
--------------------------------------------------------------------------------------------------------------------------------------------------------
Conventional.................................. 1,855,319 855,054 0 2,710,373 7,072,298 1,453,081 11,235,752
Toxic Organics................................ 108,018 70,367 0 178,385 450,458 92,551 721,394
Toxic Metals.................................. 33,877 14,755 0 48,632 90,535 18,602 157,769
Nonconventional............................... 1,490,602,961 560,011 0 1,491,162,972 2,571,382,167 528,318,780 4,590,863,919
---------------------------------------------------------------------------------------------------------
Total Pollutants (lbs/year)............... 1,492,600,175 1,500,187 0 1,494,100,362 2,578,995,458 529,883,014 4,602,978,834
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Under the current permit requirements baseline, removals (excluding TWC effluent) would result from: zero discharge for Major Pass facilities,
discharge limits for Cook Inlet produced water, and current limits for Cook Inlet drilling fluids and drill cuttings.
\2\ Under the alternative baseline, removals (Excluding TWC effluent) would result from zero discharge of produced water for Louisiana open bay and
Texas individual permit applicants, in addition to those removals already presented under the baseline for current permit requirements.

B. Quantitative Estimate of Benefits.

(1) Current Requirements Baseline
(a) Quantified Non-Monetized Benefits--Gulf of Mexico. The benefits
associated with zero discharge of produced water under the current
requirements baseline include only non-monetized benefits (i.e., (i)
review of case studies of environmental impacts of produced water that
document adverse chemical and biological impacts resulting from current
discharges into the Gulf of Mexico coastal area; (ii) modeled water
quality benefits expressed as elimination in exceedances of human
health or aquatic life state water quality standards for major deltaic
pass facilities; and (iii) projected individual cancer risk reduction
from consumption of seafood contaminated with Ra^{226 and Ra^{228
based on modeled levels for major deltaic pass dischargers. EPA could
not estimate the potential number of cancer cases avoided and monetize
benefits for these facilities, however, because the exposed angler
population could not be determined for major pass facilities alone.
(i) Documented Case Studies. A comprehensive review of available
data identified 25 study sites (12 in Louisiana and 13 in Texas) that
examined impacts of produced water discharges on the coastal
environment. The detailed description and complete references for these
studies are presented in the WQBA included in the rulemaking record.
The majority of evaluated study sites are in water depths less than 3
meters, and include variable environments (i.e., wetlands, salt
marshes, and fresh or brackish marshes), and both relatively low and
high energy areas. The documented impacts show elevated hydrocarbons
and metals in water column and sediments, and reveal impacts on biota
(i.e., depressed community structure such as abundance or diversity)
from the produced water discharge between 800 to 1000 meters in dead-
end canals and effluent dominated creeks or bayous. The salinity
effects are typically detected up to 300 meters from the discharge, and
up to 800 meters in dead-end canals. A benthic dead zone (no benthic
fauna) is documented up to 15 meters and severely depressed benthic
communities are noted to 150 to 400 meters from produced water
outfalls.
(ii) Projected Water Quality Benefits--Major Deltaic Pass
Facilities. EPA evaluated the effects of toxic pollutants in current
produced water discharges on receiving water quality. Of the 49 toxic
and nonconventional produced water pollutants (representing
subcategory-wide produced water discharge), plume dispersion modeling
was performed to project in-stream concentrations of 11 toxic
pollutants with specified water quality standards in Louisiana. (There
are no specified water quality standards for the other 38 pollutants).
Pollutant concentrations were projected at the edge of state-prescribed
mixing zones for acute and chronic aquatic, and human health standards
for Louisiana. Site-specific cases (including ambient water depth and
operational data) were developed for five (of six) major deltaic pass
facilities/dischargers. (The effects of current discharges for one
discharger was not evaluated because of the lack of site-specific
ambient data.)
Of the six major deltaic pass dischargers, all five that were
evaluated are projected to have discharges that exceed applicable human
health or aquatic life water quality standards. Five dischargers are
modeled to exceed the human health standard for benzene and the acute
standard for copper. One discharger is modeled to exceed the acute
aquatic life standard for toluene, and another to exceed the chronic
aquatic life standards for copper and nickel. The final guideline's
zero

[[Page 66114]]

discharge requirement would eliminate all projected exceedances.
EPA recognizes that in the absence of this rule, the permit issuing
authority (the State of Louisiana or EPA in Texas) would be required to
develop water quality-based effluent limits at the permitting stage.
This rule would eliminate the need to develop such limits at the
permitting stage for the pollutants of concern. It may also lessen the
possibility that the state will in the future have to develop a Total
Maximum Daily Load for the pollutants under Sec. 303(d) of the CWA.
EPA recognizes that in the absence of this rule, the permit issuing
authority (the State of Louisiana or EPA in Texas) would be required to
develop water quality-based effluent limits at the permitting stage.
This rule would eliminate the need to develop such limits at the
permitting stage for the pollutants of concern. It may also lessen the
possibility that the state will in the future have to develop a Total
Maximum Daily Load for the pollutants under section 303(d) of the CWA.
In response to late comments, EPA reevaluated its use of the water
quality model CORMIX to assess discharges to Major Deltaic Passes. In
these areas, LADEQ regulations allow the use of other appropriate
models in addition to the Complete Mix Balance Model (CMBM) specified
in regulations. EPA used CORMIX because it is technically superior to
the CMBM as discussed in the record. Nevertheless a sensitivity
analysis was conducted using the CMBM. Use of CMBM still resulted in
two of the outfalls exceeding criteria. One of these outfalls was the
largest Major Deltaic Pass discharger with exceedances for benzene.
(iii) Projected Individual Cancer Risk Reduction Benefits--Major
Deltaic Pass Dischargers. Upper bound individual cancer risks from
consuming fish contaminated with Ra^{226 and Ra^{228 from current
produced water discharges are estimated for recreational and
subsistence anglers. To estimate Ra^{226 and Ra^{228 levels in
seafood, EPA uses modeled effluent data, i.e., current subcategory-wide
produced water concentrations of Ra^{226 and Ra^{228, plume
dispersion modeling at site-specific discharge rates and water depths
for five (of six) major deltaic pass facilities/dischargers with site-
specific ambient data to support modeling. [Using the estimated
Ra^{226 and Ra^{228 concentrations in seafood, EPA estimates
individual cancer risks assuming two different consumption rates of
147.3 g/day for subsistence anglers and 15 g/day for recreational
anglers]. In addition, all individual cancer risks are adjusted by
factors of 0.2 and 0.75 to account for ingestion of seafood from
locations which are not contaminated with the Ra^{226 and Ra^{228
in coastal produced water discharges].
Projected individual cancer risks for 5 evaluated major deltaic
pass facilities range from 2.4 x 10^{-5 to 6.3 x 10^{-4 for
subsistence anglers and from 1.0 x 10^{-6 to 2.8 x 10^{-5 for
recreational anglers. The Coastal Guidelines' zero discharge
requirement for produced water will eliminate these estimated cancer
risks over time.
EPA could not estimate the potential number of cancer cases avoided
and monetize benefits for these facilities, however, because the
exposed angler population could not be determined for major pass
facilities alone.
(b) Quantitative Non-Monetized Benefits--Cook Inlet.
EPA analyzed non-monetized quantitative benefits associated with
the Coastal Guidelines for produced water in Cook Inlet. These benefits
include modeled water quality benefits expressed as reduction of mixing
zone needed for produced water discharges to meet Alaska state water
quality standards. (Effects of current drilling fluids and drill
cuttings discharge are also evaluated, however, because this rule does
not require a change in current practice no benefits are projected.)
Produced Water
EPA evaluated the effects of toxic pollutants in current produced
water discharges on receiving water quality and the benefits of the
final Coastal Guidelines. Site-specific plume dispersion modeling is
performed to project in-stream concentration of 16 toxic and
nonconventional pollutants at the edge of mixing zones from eight
facilities constituting all of Cook Inlet produced water dischargers.
The in-stream concentrations are then compared to the Alaska's state
limitations. Unlike the Gulf of Mexico, Alaska state requirements do
not have spatially-defined mixing zones. (Alaska determines the extent
of mixing zone needed to achieve compliance with water quality
standards and evaluates the reasonableness of this calculated mixing
zone). The water quality assessment for Cook Inlet therefore determines
the spatial extent of mixing zones needed for each evaluated outfall to
meet all state standards at current discharge and at the final BAT. For
the eight outfalls modeled, the distance from each facility where all
standards are met ranges from within 100 meters to 3,500 meters at
current level, and from within 100 meters to 1,000 meters for the final
BAT.
2. Alternative Baseline
Under the alternative baseline, EPA investigated the impacts that
Louisiana Open Bay dischargers and Texas individual permit applicants
have on the coastal environment and projected the benefits associated
with zero discharge of produced water for these dischargers. The
projected quantified benefits include both: (a) Non-monetized benefits
(i.e., (i) reviewed a case study of environmental effects of Louisiana
open bay produced water dischargers; (ii) modeled water quality
benefits expressed as elimination in exceedances of human health or
aquatic life state water quality standards; and (iii) projected
individual cancer risk reduction from consumption of seafood
contaminated with Ra^{226 and Ra^{228 based on modeled levels;
and (b) monetized benefits (i.e., (i) estimated avoidance of projected
cancer cases (from consumption of seafood contaminated with Ra^{226
and Ra^{228 based on modeled levels) from Louisiana open bay and
Texas permit applicant dischargers); and (ii) estimated ecological
benefits of a zero discharge requirement for produced water open bay
dischargers in Louisiana and permit applicants in Texas.
(a) Quantified Non-Monetized Benefits for Louisiana Open Bay and
Texas Individual Permit Dischargers.
(i) The United States Department of Energy (DOE) conducted a study
entitled Risk Assessment for Produced Water Discharges to Louisiana
Open Bays, March, 1996 (hereafter, ``DOE study''), included in the
rulemaking record. This study evaluated potential human health and
environmental risks from discharges of produced water to Louisiana open
bays. The DOE study concluded that: ``human health risks from radium in
produced water appear to be small'', and ``ecological risks from radium
and other radio nuclides in produced water also appear to be small''.
The DOE study also concluded that: ``intakes of chemical contaminants
in fish caught near open bay produced water discharges are expected to
pose a negligible toxic hazard or carcinogenic risk'', that a
``potential impacts to benthic biota and fish and crustaceans in the
water column are possible within the 200 ft mixing zone'', but a
``permanent damage to populations of organisms and ecosystems are not
expected because mixing zones represent relatively small volumes and
animals are not expected to remain continuously in the plume''.
EPA believes that the study shows that there are impacts from
coastal discharges, particularly regarding the

[[Page 66115]]

whole effluent toxicity and sediment contamination. Whole effluent
toxicity risk assessment of Louisiana open bay dischargers conducted by
the DOE study indicate that at 50 and 200 feet mixing zones 23 percent
and 18 percent of modeled effluents exceed their respective LC50 values
for mysids and sheep head minnows, and 57 percent and 56 percent of
modeled effluents exceed their survival and growth-inhibition NOEL
values, respectively, for mysids and sheep head minnow at 200 feet
mixing zone. A sediment toxicity in excess of sediment quality ``Effect
Range Low'' (ERL) and ``Effect Range Medium'' (ERM) criteria for heavy
metals and total and individual PAH's is also documented by the study.
(The measured values above ERL value, but less than ERM value
``represent a possible-effects range within which effects would
occasionally occur''. Concentrations at or above the ERM value
``represent a probable effect range within which effect would
frequently occur'' (Long, E.R., D.D. Macdonald, S.L. Smith, F.D.
Calder, 1995, ``Incidence of Adverse Biological Effects Within Ranges
of Chemical Concentrations in Marine and Estuarine Sediments'',
Environmental Management 19:81-97).) Metals, arsenic and nickel are
measured in excess of ERL value up to 500 m and 1000 m from discharge,
respectively. The total and individual PAH's in excess of ERL are
measured up to 500 m from discharge. The total PAH's, high molecular
weight PAH's, and individual PAHs are also measured near discharge.
(ii) Projected Water Quality Benefits. The effects of toxic
pollutants in current produced water discharges on receiving water
quality and benefits associated with the Coastal Guidelines are
evaluated. Of the 49 produced water pollutants (representing
subcategory-wide produced water discharge), plume dispersion modeling
is performed to project in-stream concentrations of 11 toxic pollutants
with specified state water quality standards in Louisiana and in Texas.
(There are no specified water quality standards for the other 38
pollutants in Louisiana and in Texas). Pollutant concentrations are
projected at the edge of state-prescribed mixing zones for acute and
chronic aquatic water quality standards, and human health water quality
standards for Louisiana and Texas.
Estimated flow-weighted average ambient water depth characteristic
and operational data are used for 69 Louisiana's open bay outfalls, and
82 Texas individual permit applicants. A mean discharge rate of 4,780
bpd and flow-weighted mean depth of 1.73 meters are used for Louisiana
open bay dischargers, and mean discharge rate of 827 bpd and flow-
weighted mean water depth of 1.66 meters for Texas permit applicants.
Eighteen of the 69 evaluated Louisiana's open bay outfalls are
projected to exceed: acute aquatic life standards for two pollutants
(copper and toluene); chronic aquatic life standards for four
pollutants (copper, nickel, lead, and toluene); and human health
standards for one pollutant (benzene). These 18 outfalls represent 79
percent of Louisiana's open bay total daily discharge flow. In Texas,
eighteen of the 82 evaluated individual permit applicants are projected
to exceed the acute and chronic aquatic life standards for silver.
These 18 applicants represent 84 percent of the total produced water
flow for the 82 applicants. The final guideline's zero discharge
requirement would eliminate all projected exceedances.
EPA recognizes that in the absence of this rule, the permit issuing
authority (State of Louisiana or EPA in Texas) would be required to
develop water quality-based effluent limits at the permitting stage.
This rule would eliminate need to develop such limits at the permitting
stage for the pollutants of concern. It may also lessen the possibility
the state will in the future have to develop a Total Maximum Daily Load
for the pollutants under section 303(d) of the CWA.
(iii) Projected Individual Cancer Risk Reduction Benefits. Upper
bound individual cancer risks from consuming fish contaminated with
Ra^{226 and Ra^{228 from current produced water discharges are
estimated for recreational and subsistence anglers. To estimate
Ra^{226 and Ra^{228 levels in seafood, EPA uses: modeled effluent
data, i.e., current subcategory-wide produced water concentrations of
Ra^{226 and Ra^{228; plume dispersion modeling at average outfall
discharge rates and flow-weighted ambient average depths for 69
Louisiana open bay outfalls and 82 Texas individual permit applicant
dischargers; and consumption rates as described in the section
XII.B.1.(a)(iii) of this preamble.
Projected individual cancer risks from Louisiana open bay
dischargers range from 2.9 x 10^{-4 to 1.1 x 10^{-3 for
subsistence anglers and from 1.3 x 10^{-5 to 4.8 x 10^{-6 for
recreational anglers. For Texas individual permit applicants, the
projected individual cancer risks range from 3.7 x 10^{-5 to
1.4 x 10^{-4 for subsistence anglers and from 1.6 x 10^{-6 to
6.1 x 10^{-6 for recreational anglers. The Coastal Guidelines' zero
discharge requirements for produced water will eliminate these
estimated cancer risks over time, resulting in projected elimination of
0.43 to 1.66 cancer cases per year for anglers consuming fish from the
Louisiana open bay dischargers and Texas individual permit applicant
dischargers (i.e., 0.35 to 1.34 and 0.08 to 0.32 annual cancer cases in
Louisiana and Texas, respectively)
(b) Quantified Monetized Benefits for Louisiana Open Bay and Texas
Permit Applicant Dischargers.
(i) Projected Cancer Risk Reduction Benefits by Reducing Exposure
to Radium in Produced Water. The projected avoidance of 0.43 to 1.66
cancer cases per year for anglers consuming fish from Louisiana open
bay dischargers and Texas individual permit applicant dischargers will
result in combined monetized benefits in $1.1 to $22.3 million per year
($1995) range (including $0.9 to $18 million per year ($1995) for
Louisiana open bay dischargers and $0.2 to $4.3 million per year
($1995) for Texas individual permit applicants).
The temporal dynamics of both impacts and benefits assessments is
relevant to the human health risk assessment. For the assessments of
cancer reduction benefits, the methodology is consistent with
estimating costs for the rule, using a one-year ``snap-shot'' approach.
Allocating the full value of annual benefits within one year following
cessation of produced water discharges may appear to over-estimate
potential annual benefits in cases where incomplete recovery has
occurred. However, in such cases where impacts are incompletely
recovered, a consideration of total impact would need to include any
impacts expected to occur beyond that year. This analysis does not
attempt to identify or allocate benefits on a yearly basis, but merely
averages total benefits so that monetized benefits may be compared to
costs that are developed using the same approach.
In response to late comments, EPA revised the population estimate
of exposed individuals to reflect only coastal counties within 65 miles
of the coast. The number of resident recreational anglers who only fish
in state waters was adjusted by the proportion of state residents in
coastal counties. EPA also received late comments to the effect that it
should have used the monitoring data from the DOE study rather than
EPA's modeled data. As is discussed further in the record, EPA
continued to use the modeled effluent data rather than limited
monitoring data to estimate risk. Although EPA modeling predicts radium
concentrations significantly

[[Page 66116]]

higher than those measured in the DOE study, EPA believes it is not
appropriate to use migratory fish species to represent tissue levels of
all fish around platforms because EPA has information indicating that
some resident species in coastal areas spend a significant amount of
time in coastal waters.
(ii) Projected Ecological Benefits. A potential ecological benefit
of zero discharge of produced water in Louisiana open bays and Texas
individual permit applicants dischargers is projected from a Trinity
Bay case study. Extrapolating from this case study is only applicable
to shallow bay ecosystems contiguous with the Gulf of Mexico open bay
discharge sites that are represented by the Louisiana open bay
dischargers and the great majority of Texas individual permit applicant
dischargers. This Trinity Bay study shows that sediment near the
outfall (within 15 meters) were devoid of biota and that depressions in
benthic abundance and species richness were not recovered until
distances between 1.7 and 4 kilometers from the point of discharge.
(Data on abundance of other species, such as waterfowl were not
collected). Taking into account an integration of the severity of these
impacts at different distances, the equivalent acreage affected in this
case study ranges from 200 to 2,817 acres.
The analysis of this study is based on naphthalene concentration in
sediment and extremely tight correlation between sediment naphthalene
levels and benthic community structure parameters. In response to
comments, EPA has adjusted the basis for projecting these effects
because of the pre-BPT effluent quality of this study site and adjusted
the acreage affected by the proportion between the Trinity Bay effluent
naphthalene level (300 ppb) and current effluent naphthalene levels
(184 ppb) to a 123 to 1,727 acres range.
EPA estimates that the total Louisiana and Texas open bay acreage
affected by coastal oil and gas produced water discharges ranges from
6,918 acres to 97,438 acres (i.e., 5,739 to 80,828 acres in Louisiana
and 1,179 to 16,610 acres in Texas). EPA identifies numerous values for
an acre of wetland but none are marginal estimates for Texas or
Louisiana, and some did not subtract the cost of recreational use.
There may be concern that the value of wetland recovery diminishes as
the amount of recovered acreage increases and therefore these average
values would overstate the relevant marginal values by an unknown
amount. A literature review for wetland value estimates conducted for
the Mineral Management Service (MMS), Department of Interior in 1991,
reports that different studies have estimated recreational and
commercial wetland values for coastal Louisiana ranging from $57 to
$940 per acre per year (with a median value of $410 per acre per year)
in 1990 dollars.
Using this range of values inflated to 1995 dollars, the estimated
increase of Louisiana and Texas Bay recreational values from zero
discharge of produced water ranges from $0.48 million to $106.8 million
per year (i.e., $0.4 to $88.6 million/year in Louisiana and $0.08 to
$18.2 million/year in Texas).
These per acre estimates are consistent with the estimated average
recreational value of the acreage of Galveston Bay, which ranges from
$336 to $730 per acre. ($1990) (The Galveston Bay estimates do not
subtract the cost to recreational users of using the resource.) These
estimates may not be marginal values as they are calculated from the
total recreational value of Galveston Bay and total acreage of the Bay.
As these studies use different estimation methods, cover different
types of wetlands, marshes and coastal waters which may differ from
those affected by this rule, and generally reflect average values
rather than the social valuation of small (marginal) changes in
acreage, EPA at proposal requested data on marginal values of wetlands,
in particular in Louisiana and Texas. However, EPA did not receive any
data on wetland values or any comments related to the values used in
benefit analysis for the proposed rule.
In response to late comment, EPA performed a sensitivity analysis
to assess the acreage affected based on the results of Trinity Bay
study. EPA's approach uses a maximum observed species abundance and
richness at 1677 and 3963 meters from the platform as a measure of
background. This range is based on collecting species using two
different sieve sizes. EPA believes that this is appropriate because a
true measure of background cannot be determined since oil and gas
facilities discharges have occurred in this water body for over 40
years. In late comments, some suggested that EPA instead use the
average abundance of species richness beyond 686 meters as a
background. Using this suggested approach substantially reduces the
impacted area. More details are provided in the record.
The authors of the Trinity Bay study state that stations beyond 457
meters or further are unaffected by the platform. Based on the authors
estimated impact area of 457 meters rather than EPA's estimated range
of 1677-3963 meters, the estimated average impacted acreage would be 51
acres. Using this methodology, the total monetized benefits are $0.12--
$1.9 million ($1995) based on wetland values of $66--$1087 ($1995). EPA
does not believe this is an appropriate impacted area because maximum
species abundance and richness occurs between 1677 and 3963 meters.
Furthermore sediment napthalene levels, which can adversely effect
aquatic species, are the lowest at 4,000 meters. Both stations beyond
4,000 meters have lower species abundance and richness. Both these
stations are contaminated with naphthalene at levels that exceed Effect
Range Median (ERM) for naphthalene. The ERM represents the
concentrations at which adverse effects are frequently associated.
(iii) Total Monetized Benefits. EPA estimates that total monetized
benefits (i.e. combining cancer risk reduction and ecological benefits)
resulting from zero discharge of produced water for Louisiana open bay
dischargers and Texas individual permit applicants dischargers range
from approximately $1.6 million to $129.1 million per year ($1995)
(i.e., $1.3 to $106.6 million/year in Louisiana and $0.3 to $22.5
million/year for Texas individual permit operators).

C. Description of Non-Quantified Benefits

The WQBA attempts to quantify the environmental effects, and
whenever appropriate, to monetize specific environmental benefits that
may result from the Coastal Guidelines. However, some of the potential
benefits could not be quantified or monetized because of the lack of
data, or because sufficient information to define the causal
relationship between dischargers covered by the Coastal Guidelines and
environmental effects is not available. This analysis includes: (1) An
assessment of potential health risks to the Alaska's Native Populations
from consumption of Cook Inlet's fish and shellfish and potential link
between coastal oil and gas discharges and fish consumed by native
populations; (2) effects on threatened or endangered species and
migratory waterfowl, and potential benefits of the Coastal Guidelines
on ecosystem health primarily for coastal areas of Gulf of Mexico and
to a limited degree for Cook Inlet.
(1) An Assessment of Health Risks to Cook Inlet's Native
Populations. EPA received comments from Native Americans concerned
about coastal oil and gas discharges in Cook Inlet. The Chugachmuit
Environmental Protection Consortium (CEPC) of Anchorage, Alaska raised
concerns about the

[[Page 66117]]

impacts that oil and gas exploration and development activities in Cook
Inlet and Kachemak Bay, Alaska have on the subsistence lifestyle of the
Native Tribes of Port Graham and Nanwalek, and provided fish
consumption data. EPA evaluated this data and all other data about the
environmental impacts of coastal oil and gas discharges in Cook Inlet.
EPA attempted to assess the potential health risks posed from the high
subsistence use of Cook Inlet by native populations related to the
discharges from coastal oil and gas facilities. Although sufficient
information on the Cook Inlet's native population subsistence patterns
exists, there is little fish tissue data with which to assess the risks
from consumption of fish and shellfish from Cook Inlet. Two available
studies provide some mussels tissue data, but no data on fish or other
shellfish. One study investigated the occurrence of petroleum
hydrocarbons, naturally occurring radioactive materials, and trace
metals in water, sediments, and biota (mussels) in lower Cook Inlet.
Very low levels of PAHs (including naphthalene) were found in mussel
samples but the source of the PAHs could not be identified. The authors
also found no anomalous trends evident from the mussels metals
concentrations. Another Cook Inlet study, using caged mussels, found
low levels of hydrocarbons in mussel tissue that were within a range of
concentrations observed in organisms from unpolluted offshore
environments. The study was conducted as part of environmental
monitoring program to determine impacts of oil industry operations in
Cook Inlet.
The mussel data may provide an upper bound of contaminant
concentrations likely to be found in other shellfish. However, the data
is insufficient to assess risk from consumption of fish. EPA cannot
predict finfish contaminant concentrations based on mussel data because
mussels have much higher bioaccumulation rates. Finfish tend to more
rapidly metabolize and excrete contaminants (e.g., PAHs). In addition,
mussels and shellfish in general represent only small portion (i.e.,
two to eight percent) of the fish and shellfish subsistence harvest for
three Cook Inlet's native villages (i.e., Tyonek, Nanwalek and Port
Graham). Finfish represent 74 to 80 percent of the harvest, (with
salmon representing 57 to 97 percent of the finfish harvest). The
finfish harvest data indicate consumption levels could be as high as
211 g/day, 238 g/day and 298 g/day (with salmon consumption levels of
121 gpd, 232 gpd, and 180 gpd) in Port Graham, Tyonek and Nanwalek,
respectively. The shellfish harvest data indicate consumption levels of
6 g/day, 20 g/day, and 29 g/day in Tyonek, Port Graham, and Nanwalek,
respectively. These consumption levels are higher then the subsistence
consumption levels used in this WQBA for the Gulf of Mexico region.
However, lacking the data on the concentration of pollutants in fish
tissue, which represent up to 80 percent of the Cook Inlet's native
population fish and shellfish intake rates, it is difficult to assess
the human health risks from fish consumption, and to reasonably
establish the link between coastal oil and gas discharges and human
health effects from the discharges in Cook Inlet. EPA is, however,
concerned about the potential for human health effects. Therefore, EPA
will continue to monitor ongoing sediment, water quality and biological
studies in Cook Inlet for applicability to future permit actions.
(2) Effects on Threatened and Endangered Species. The zero
discharge of produced water may also have beneficial effects on 32
threatened and endangered species in coastal areas of Texas and
Louisiana, including open bays and the major deltaic passes of the
Mississippi River. Such threatened and endangered species include the
Brown Pelican, Hawksbill Sea Turtle, Leatherback Sea Turtle, Ocelot,
and others that use these areas as part of their habitat.
The control of produced water discharges by the Coastal Guidelines
may also have beneficial effects on Cook Inlet biological resources.
The Upper Cook Inlet serves as an important pathway for spawning fish
and non-endangered mammals, provides critical habitat for seabirds,
shorebirds, and migrating waterfowl, and at least four endangered
cetacean species and endangered avian species which may occur as
migrants in or near Cook Inlet.

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

A. Pollution Prevention Act

In the Pollution Prevention Act of 1990 (PPA) (42 U.S.C. 13101 et
seq., Pub. L. 101-508, November 5, 1990), Congress declared pollution
prevention the national policy of the United States. The PPA declares
that pollution should be prevented or reduced whenever feasible;
pollution that cannot be prevented or reduced should be recycled or
reused in an environmentally safe manner wherever feasible; pollution
that cannot be recycled should be treated in an environmentally safe
manner wherever feasible; and disposal or release into the environment
should be chosen only as a last resort.
Today's rules are consistent with the PPA. EPA developed these
rules while focused on pollution-preventing technologies. The closed-
loop recycle systems for drilling fluids and the achievement of zero
discharge for produced water by injection form a substantial basis for
this rule.

B. Paperwork Reduction Act

The Coastal Guidelines place no additional information collection
or record-keeping burden on respondents. Therefore, an information
collection request has not been prepared for submission to the Office
of Management and Budget (OMB) under the Paperwork Reduction Act, 44
U.S.C. 3501 et seq.

C. Regulatory Flexibility Act

Pursuant to section 605(b) of the Regulatory Flexibility Act, 5
U.S.C. 605(b), the Administrator certifies that this rule will not have
a significant economic impact on a substantial number of small
entities. EPA analyzed the potential impact of the rule on small
entities under several scenarios. Under the most conservative scenario
(i.e. the scenario that assumes the largest number of small entities
potentially affected by the rule), EPA's analysis shows that most small
entities are already in compliance or are already covered by permit
requirements equivalent to the rule's discharge requirements. Thus, the
rule will not have any adverse economic impact on them. Under this same
scenario, approximately 58 out of 372 small entities might have to take
some action to achieve compliance. Even a smaller number of entities
(34) may experience costs greater than one percent of revenues. Based
on this analysis, EPA believes that the economic impact of the rule
will not be significant for a substantial number of small entities.
Under the Regulatory Flexibility Act, an agency is not required to
prepare a regulatory flexibility analysis for a rule that the agency
head certifies will not have a significant economic impact on a
substantial number of small entities. While the Administrator has so
certified today's rule, the Agency nonetheless prepared a regulatory
flexibility assessment equivalent to that required by the Regulatory
Flexibility Act as modified by the Small Business Regulatory
Enforcement Fairness Act of 1996. The assessment for this rule is
detailed in the Economic Impact Analysis. Although not required by the
Regulatory Flexibility Act, EPA also

[[Page 66118]]

analyzed the indirect economic impact of the Coastal rule on small
communities. Indirect impacts are those impacts felt by entities not
subject to the rule. Some of the royalty losses caused by the rule may
be felt at the local level. To determine the significance of this
indirect impact, EPA assumes that 50 percent of the total royalty
losses would be borne by local county and parish revenues. In the
offshore rule, local governments were estimated to receive
approximately 3 percent of royalties. As a result, EPA considers the 50
percent assumption a significant overestimation that nonetheless serves
to underscore the limits of the rule's indirect impact on local
communities. EPA determined that spreading royalty losses over the
population of counties and parishes adjacent to affected coastal waters
would result in a per capita cost of $0.12, or 0.002 percent of per
capita income in Texas counties, and a per capita cost of $0.44 to
$1.30 in Louisiana , which represents 0.004 to 0.012 percent of per
capita income in affected parishes under the regulatory requirements
and alternative baselines, respectively. EPA thus concludes that the
indirect impacts of the rule are not significant.

D. Small Business Regulatory Enforcement Fairness Act of 1996
(Submission to Congress and the General Accounting Office)

Under 5 U.S.C. 801(a)(1)(A) as added by the Small Business
Regulatory Enforcement Fairness Act of 1996, EPA submitted a report
containing this rule and other required information to the U.S. Senate,
the U.S. House of Representatives and the Comptroller General of the
General Accounting Office prior to publication of the rule in today's
Federal Register. This rule is not a ``major rule'' as defined by 5
U.S.C. 804(2).

E. Unfunded Mandates Reform Act

Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), P.L.
104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures to State, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million or more in any
one year. Before promulgating an EPA rule for which a written statement
is needed, section 205 of the UMRA generally requires EPA to identify
and consider a reasonable number of regulatory alternatives and adopt
the least costly, most cost-effective or least burdensome alternative
that achieves the objectives of the rule. The provisions of section 205
do not apply when they are inconsistent with applicable law. Moreover,
section 205 allows EPA to adopt an alternative other than the least
costly, most cost-effective or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted. Before EPA establishes any regulatory
requirements that may significantly or uniquely affect small
governments, including tribal governments, it must have developed under
section 203 of the UMRA a small government agency plan. The plan must
provide for notifying potentially affected small governments, enabling
officials of affected small governments to have meaningful and timely
input in the development of EPA regulatory proposals with significant
Federal intergovernmental mandates, and informing, educating, and
advising small governments on compliance with the regulatory
requirements.
EPA has determined that this rule does not contain a Federal
mandate that may result in expenditures of $100 million or more for
State, local, and tribal governments, in the aggregate, or the private
sector in any one year. While EPA does not believe the rule imposes
significant or unique effects on small governments, under section 203
and 205 of the UMRA, EPA has consulted with state governments as
described in Section XIII. The estimated annual cost of the Coastal
Guidelines, presented in Section VIII of this preamble, is $16.4
million when estimated using the current requirements baseline and
$50.6 million when estimated using the alternative baseline. Thus,
today's rule is not subject to the requirements of sections 202 and 205
of the UMRA.

F. Executive Order 12866 (OMB Review)

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

G. Common Sense Initiative

On August 19, 1994, the Administrator established the Common Sense
Initiative (CSI) Council in accordance with the Federal Advisory
Committee Act (5 U.S.C. Appendix 2, Section 9 (c)) requirements. A
principal goal of the CSI includes developing recommendations for
optimal approaches to multimedia controls for industrial sectors
including Petroleum Refining, Metal Plating and Finishing, Printing,
Electronics and Computers, Auto Manufacturing, and Iron and Steel
Manufacturing.
The Coastal Guidelines were not among the rulemaking efforts
included in the Common Sense Initiative. However, many oil and gas
producers (mostly large companies) involved in coastal oil and gas
extraction activities also have refineries. These companies are
projected to incur costs associated with the requirements contained in
this proposal, though these costs are not projected to have an economic
impact at the firm level. The CSI objectives, described at proposal,
have been incorporated into the Coastal Guidelines and the Agency
intends to continue to pursue these objectives. The Agency particularly
will focus on avenues for giving state and local authorities
flexibility in implementing this rule, and giving the industry
flexibility to develop innovative and cost effective compliance
strategies. In developing this rule, EPA took advantage of several
opportunities to gain the involvement of various stakeholders. Section
XIII of this preamble references consultations with state and local
governments and other parties including the industry. EPA has also
coordinated among relevant program offices in developing this rule.
Section XII describes related rulemakings that are being developed by

[[Page 66119]]

EPA's Office of Air Quality, Planning and Standards, Underground
Injection Control Program, and Spill Prevention, Control and
Countermeasure Program. EPA will be monitoring these related
rulemakings to assess their collective costs to the industry. Section
IX of the preamble describes the non-water quality environmental
impacts this proposed rule would have on other media including air
emissions and solid waste disposal.

XII. Related Rulemakings

In addition to these Coastal Guidelines, EPA is in the process of
developing other regulations that specifically affect the oil and gas
industry. These other rulemakings are summarized below. EPA's offices
are coordinating their efforts with the intent to monitor these related
rulemakings to assess their collective costs to industry.

A. National Emission Standards for Hazardous Air Pollutants

National emission standards for hazardous air pollutants are being
developed for the oil and gas production industry by EPA's Office of
Air Quality, Planning and Standards (OAQPS), under authority of section
112 (d) of the Clean Air Act as amended in 1990. Section 112 (d) of the
Clean Air Act directs the EPA to promulgate regulations establishing
hazardous air pollutant (HAP) emissions standards for each category of
major and area sources that has been listed by EPA for regulation under
section 112 (c). The 189 pollutants that are designated as HAP are
listed in section 112 (d). For major sources, or facilities which emit
10 or more tons per year (TPY) of an individual HAP pollutant or 25 or
more TPY of multiple HAPs, the air emission standards are based on
``maximum achievable control technology'' or MACT.
Major sources within the coastal oil and gas subcategory have been
identified by OAQPS as stand alone glycol dehydrators, tank batteries,
gas plants, and offshore production platforms. In most cases, OAQPS
believes that, in order to be a major source, a coastal production
facility must have glycol dehydrators located on-site. A production
facility alone may not produce enough emissions to be classified as a
major source.
EPA plans to propose MACT standards for the oil and gas industry by
March 1997. OAQPS estimates that the total annual cost of these
standards is $16.5 million.

B. Requirements for Injection Wells

The Safe Drinking Water Act (SDWA) charges EPA with protecting
underground sources of drinking water (USDW). As part of this mandate,
EPA developed the Underground Injection Control (UIC) program to
regulate the underground injection of all fluids, including produced
water. EPA first promulgated regulations concerning the construction,
operation, and closure of Class II injection wells for the disposal of
oil and gas industry wastes in 1980 (45 FR 42500, June, 24, 1980).

C. Spill Prevention, Control, and Countermeasure

EPA's Oil Pollution Prevention regulation at 40 CFR part 112, which
requires Spill Prevention, Control, and Countermeasure (SPCC) plans,
was promulgated in 1973 under section 311 (j) of the CWA. The SPCC
planning requirement applies to all oil extraction and production
facilities that have an oil storage capacity above certain thresholds
(i.e. an overall aboveground oil storage capacity greater than 1,320
gallons or greater than 660 in a single container, or an underground
oil storage capacity of greater than 42,000 gallons) and are located
such that a discharge could reasonably be expected to reach U.S.
waters. EPA estimates that there are approximately 450,000 SPCC-
regulated facilities. A preliminary estimate indicates that
approximately 3,000 of these facilities may be either coastal or
offshore facilities.
Under part 112, facility owners or operators are required to
prepare and implement written SPCC plans that discuss conformance with
procedures, methods, and equipment and other requirements to prevent
discharges of oil and to contain such discharges.
On July 1, 1994, (59 FR 34070, July 1, 1994) EPA issued a final
rule amending part 112 to require certain onshore facilities to
prepare, submit to EPA, and implement plans to respond to a worst case
discharge of oil to meet section 4202(a) of the Oil Pollution Act
(OPA). EPA also intends to develop requirements in 1997 under section
4202(a) of OPA specifically for coastal facilities. (Note: Coastal and
offshore facilities in the part 112 program are collectively referred
to as ``offshore''. However, the intended OPA rulemaking specifically
applies to facilities landward of the inner boundary of the territorial
seas, and that are not onshore.) These regulations would, among other
things, require that owners or operators of coastal facilities prepare
and submit to the Federal government a plan for responding to a worst
case discharge of oil.

D. Shore Protection Act Regulations

EPA, in conjunction with the Department of Transportation, has
developed proposed regulations that would establish waste handling
practices for vessels and waste transfer stations for the hauling and
handling of municipal and commercial wastes. This rule would assure
that wastes will not be deposited into coastal waters during loading,
off loading, and transport. The proposal was signed by the
Administrator on August 19,1994 and published in the Federal Register
on August 30 (59 FR 44798). Promulgation is planned for March 1997.
While this regulation will apply to operators of supply vessels used by
coastal oil and gas extraction facilities, it will not directly impact
the ability of coastal oil and gas extraction facilities to comply with
effluent limitations guidelines and standards.

XIII. Summary of Public Participation

EPA encouraged full public participation in the development of the
final Coastal Guidelines. Written comments were received on the 1989
Notice of Information and Request for Comments (54 FR 46919; November
8, 1989), industry trade associations and the Natural Resources Defense
Council, Inc. participated in the development of EPA's questionnaire
for the coastal oil and gas extraction industry, written comments were
received on the proposed rule (60 FR 9428; February 17, 1995), and
public meetings were held.
On July 19, 1994, EPA held a public meeting in New Orleans,
Louisiana about the content and the status of the proposed regulation.
The meeting was announced in the Federal Register (59 FR 31186; June
17, 1994), and information packages were distributed at the meeting.
The public meeting also gave interested parties an opportunity to
provide information, data, and ideas to EPA on key issues.
Additional public meetings were held on March 7, 1995 and March 21,
1995. The first of these meetings was held in New Orleans, Louisiana
and the second in Seattle, Washington.
Meetings have been held with representatives from industry and
environmental groups, as well as state and other federal agencies.
These meetings are documented in the record.
EPA has formally assessed all comments and data received: at the
July 19, 1994 public meeting, during the public comment period for the
proposed rule, and as a result of the 1989 Notice of Information.
Responses to these

[[Page 66120]]

comments are provided in the Comment Response Document for Final
Effluent Guidelines and Standards for the Coastal Subcategory of the
Oil and Gas Extraction Category, which is in the record. In addition,
as time allowed, EPA considered late comments.

XIV. Regulatory Implementation

A. Toxicity Limitation for Drilling Fluids and Drill Cuttings

EPA is establishing a toxicity limitation for drilling fluids and
drill cuttings. The toxicity limitation would apply to any periodic
blowdown of drilling fluid as well as to bulk discharges of drilling
fluids and drill cuttings systems. The reader is referred to the
Offshore Guidelines at 58 FR 12454, 12502 (March 4, 1993) for an
explanation of the regulatory implementation for the toxicity limit.

B. Diesel Prohibition for Drilling Fluids and Drill Cuttings

Cook Inlet's oil and gas extraction platforms are prohibited from
discharging diesel oil and drilling fluids and drill cuttings
contaminated with diesel oil. The reader is referred to the Offshore
Guidelines (58 FR 12502) for a discussion on the implementation of this
requirement.

C. Upset and Bypass Provisions

A recurring issue of concern has been whether industry guidelines
should include provisions authorizing noncompliance with effluent
limitations during periods of ``upsets'' or ``bypasses''. The reader is
referred to the Offshore Guidelines (58 FR 12501) for a discussion on
upset and bypass provisions.

D. Variances and Modifications

Once this regulation is in effect, the effluent limitations must be
applied in all NPDES permits thereafter issued to discharges covered
under this effluent limitations guideline subcategory. Under the CWA
certain variances from BAT and BCT limitations are provided for. A
section 301(n) (Fundamentally Different Factors) variance is applicable
to the BAT and BCT and pretreatment limits in this rule. The reader is
referred to the Offshore Guidelines (58 FR 12502) for a discussion on
the applicability of variances.

E. Synthetic Drilling Fluids

During the Offshore Guidelines rulemaking and again after the
Coastal Guidelines proposed rule, several industry commenters noted
recent developments in formulating synthetic-based drilling fluids as
substitutes for the traditional water-based and oil-based drilling
fluids. Synthetic-based drilling fluids or synthetic-based muds (SBM)
represent a new technology which was developed in response to the oil-
based drilling fluids discharge ban in the North Sea. They were first
used in the North Sea in 1990, and the first well drilled in the Gulf
of Mexico using SBM was completed in June 1992. Operators have claimed
that compared to the discharge of water-based muds (WBM) and cuttings
and barging/hauling of cuttings from oil-based muds (OBM), the use of
the synthetics and on-site discharge of associated cuttings presents a
pollution prevention opportunity.
In the proposed Coastal Guidelines, the EPA requested additional
information on the use of synthetic fluids including well logs,
toxicity, analytical methods testing and in-situ seabed and water
column physical, chemical and biological testing. EPA received numerous
comments documenting and supporting environmental and operational
benefits achieved by SBMs. The commenters contended that in the absence
of definitions for SBM, NPDES permit restrictions on discharges of oil-
based drilling fluids and inverse emulsions were unintentionally
providing barriers to the discharge of drill cuttings generated with
SBM even though such cuttings generally pass the sheen and toxicity
tests. Based on a review of these comments EPA has identified certain
environmentally beneficial aspects of using SBM. Improved drilling
operations allow for smaller diameter holes resulting in less drill
wastes being generated. Increased solids removal in the closed loop
solids systems leads to less discharge of drilling fluids. Lower
toxicity of the drilling fluids, at least in the aqueous or suspended
particulate phase, leads to a decrease in water column toxicity
effects, and possibly a decrease in overall toxicity effects.
In considering use of these drilling fluids EPA is examining the
use of the current sheen and toxicity tests applied to the discharge of
cuttings associated with SBM. Although the existence and limited use of
SBM were known at the start of the Coastal and completion of the
Offshore rulemakings, sufficient information was not available to
propose any limitations different from those contained in the Offshore
rule at this final Coastal rule. Nevertheless, EPA will address the
concerns related to the sheen and toxicity tests by additional data
gathering in order to provide guidance to NPDES permit writers about
the use of alternative tests where the discharge of drilling wastes is
allowed. The alternative tests are a gas chromatography (GC) test and a
benthic toxicity test to verify the results of the static sheen and the
suspended particulate phase (SPP) toxicity testing currently required.
Other tests for bioaccumulation potential and biodegradation may be
appropriate for use in evaluating site specific (water quality) effects
and rates of recovery for sea floor areas covered by cuttings piles.
Such tests are already applied to SBM cuttings discharges in the North
Sea.
EPA recognizes the potential pollution prevention opportunities
presented by this new technology. Until guidelines can be written for
this wastestream, EPA is encouraging their further development by
including definitions in this rule for ``synthetic-based drilling
fluid'' and the ``synthetic material'' which comprises the SBM.
Furthermore, one commenter claimed to achieve the environmental and
performance benefits of a synthetic based drilling fluid with an
enhanced mineral oil (EMO). Since the EMOs are not synthetic based
materials and were stated to be different from previously used mineral
oils, EPA is also providing a definition for EMOs. The definitions are
as follows:

The term drilling fluid refers to the circulating fluid (mud)
used in the rotary drilling of wells to clean and condition the hole
and to counterbalance formation pressure. The four classes of
drilling fluids are:
(a) A water-based drilling fluid has water as its continuous
phase and the suspending medium for solids, whether or not oil is
present.
(b) An oil-based drilling fluid has diesel oil, mineral oil, or
some other oil, but neither a synthetic material nor enhanced
mineral oil, as its continuous phase with water as the dispersed
phase.
(c) An enhanced mineral oil-based drilling fluid has an enhanced
mineral oil as its continuous phase with water as the dispersed
phase.
(d) A synthetic-based drilling fluid has a synthetic material as
its continuous phase with water as the dispersed phase.

EPA is also introducing definitions for the ``synthetic material''
and ``enhanced mineral oil'' which comprise the respective drilling
fluids as follows:

The term enhanced mineral oil as applied to enhanced mineral
oil-based drilling fluid means a petroleum distillate which has been
highly purified and is distinguished from diesel oil and
conventional mineral oil in having a lower polycyclic aromatic
hydrocarbon (PAH) content. Typically, conventional mineral oils have
a PAH content on the order of 0.35 weight percent expressed as
phenanthrene, whereas enhanced mineral oils typically have a PAH
content of 0.001 or lower weight percent PAH expressed as
phenanthrene.
The term synthetic material as applied to synthetic-based
drilling fluid means material

[[Page 66121]]

produced by the reaction of specific purified chemical feedstock, as
opposed to the traditional base fluids such as diesel and mineral
oil which are derived from crude oil solely through physical
separation processes. Physical separation processes include
fractionation and distillation and/or minor chemical reactions such
as cracking and hydro processing. Since they are synthesized by the
reaction of purified compounds, synthetic materials suitable for use
in drilling fluids are typically free of polycyclic aromatic
hydrocarbons (PAHs) but test sometimes report levels of PAH up to
0.001 weight percent PAH expressed as phenanthrene. Poly(alpha
olefins) and vegetable esters are two examples of synthetic
materials used by the oil and gas extraction industry in formulating
drilling fluids. Poly(alpha olefins) are synthesized from the
polymerization (dimerization, trimerization, tetramerization, and
higher oligomerization) of purified straight-chain hydrocarbons such
as C 6-C 14 alpha olefins. Vegetable esters are
synthesized from the acid-catalyzed esterification of vegetable
fatty acids with various alcohols. The mention of these two
synthetic fluid base materials is to provide examples, and is not
meant to exclude other synthetic materials that are either in
current use or may be used in the future. A synthetic-based drilling
fluid may include a combination of synthetic materials.

Since the publication of the Offshore Guidelines in 1993, and
publication of the proposed Coastal Guidelines in February 1995, data
have been submitted to document the enhanced operational and
environmental performance of synthetic fluids. The data for SBMs
included: well logs, toxicity, analytical methods testing and in-situ
seabed and water column physical, chemical and biological testing.
Impacts due to the discharge of drilling fluids and associated
drill cuttings fall into two main categories: water column and sea
floor. As detailed in the Coastal Development Document, these data and
evidence presented in the literature show that use of SBM in place of
WBM may reduce the adverse environmental impact in the water column
because of (a) reduction in volume of muds discharged, (b) less
dispersion of the muds and cuttings in the water, and (c) lower
toxicity. In addition, the reduction in volume of wastes discharged may
reduce the effects to the sea floor. Due to decreased washout
(erosion), drilling of narrower gage holes, and lack of dispersion of
the cuttings in the SBM, compared to WBM the quantities of muds and
cuttings waste generated is reduced, reportedly in some cases by as
much as 70 percent. The greatest reduction seen is for the drilling
fluids. The SBM offer the opportunity for high recycle rates because
unlike the WBM the cuttings do not disperse in the fluid and so less
dilution and additives are required to keep the necessary drilling
fluid characteristics. In general the only SBM discharged is the amount
adhered to the cuttings, which ranges from 7 to 12 percent based on dry
cuttings weight. When WBM is used, the amount of drilling fluid
discharged is often 5 or 6 times greater that discharged when drilling
a similar hole with SBM. If the engineering aspects of the
effectiveness of a drilling fluid are considered as a technology to
reduce the levels of pollution, then SBM may be viewed as a control
technology for conventional pollutants.
Sea floor effects can be separated into two types: Short-term
burial effects and long-term toxic effects. The adverse impact caused
by burial can be assumed to be directly proportional to the quantity of
solids discharged, and will also depend on the dispersion of the
settling solids. As discussed earlier the synthetics have been shown to
create a lower volume of drilling wastes. Also, the cuttings which are
coated with 7-12 percent synthetic material, tend to sink without
drifting in the water column unlike the particulate matter of the WBM
which tends to disperse and stay suspended longer. Therefore as
compared to WBM one would expect the burial footprint from SBM cuttings
discharge to be smaller and have less solids. The diminished dispersion
of the SBM has been shown by relating barium concentrations on the sea
floor.
In terms of the long-term toxic effects, studies have shown that
changing the toxicity, biodegradation, and bioaccumulation of the oily
or hydrophobic constituent of the cuttings has a large effect on the
recovery of the benthic community. Most germane is a comparison of the
recolonization of WBM cuttings piles compared to that of SBM cuttings
piles. While WBM cuttings piles are said to recover ``quickly'' in the
literature, data have not been found in any source which defines just
how quickly. Thus, a comparison with the SBM recovery rates is not
possible without additional study. The recovery of synthetics
contaminated cuttings piles has been detailed in two instances known to
EPA, one contaminated with a poly(alpha olefin) (PAO) and one
contaminated with a vegetable ester. In both cases the PAO or vegetable
ester organic contamination was found to either biodegrade or otherwise
disperse to low concentrations at the eight month to one year
evaluation times. At the one year to 16 months evaluation times, the
cuttings piles were found to be in a natural state with a normal
diversity and number of benthic organisms, except at a few stations
where there was either a dominant population of one organism or
slightly elevated organic contamination. This is contrasted with the
relatively large zone of impact and much slower rate of recovery of
cuttings piles contaminated with oil from OBM.
While EPA recognizes the potential environmental benefits with the
use of SBM over WBM, EPA has some concerns about the appropriateness of
both the static sheen test used to determine compliance with the no
free oil limitation and the toxicity test associated with the suspended
particulate phase to determine compliance with the toxicity limitation.
The sheen and toxicity tests were developed for use on WBM, which
readily disperse in water, allowing components of the drilling fluid or
contaminants to rise to the surface to give a sheen or partition to the
suspended particulate phase (aqueous phase) and show toxicity.
Conversely, the cuttings from SBM sink to the sea floor with little or
no dispersion in the water. This is demonstrated in the laboratory
toxicity test. When WBM drill associated cuttings are stirred in sea
water as prescribed, the suspended particulate phase (SPP) becomes
cloudy immediately and typically remains cloudy during the one-hour
settling period. When stirring SBM or associated cuttings in sea water,
the aqueous phase typically remains clear indicating little or no
dispersion of drilling fluid, cuttings, or other components in the
aqueous phase. For this reason, EPA believes it may be inappropriate to
measure only the aquatic toxicity as part of the discharge requirement
to judge the environmental effect of the discharge of these cuttings.
The measurement of benthic toxicity may be appropriate for use in
conjunction with the aquatic phase testing as a discharge requirement.
Additional tests on bioaccumulation and biodegradation rates may be
more useful for the evaluation of the synthetic material or SBM
cuttings wastes with respect to environmental impact determinations.
In addition, previous commenters had identified the sheen test as
giving false positive results due to discoloration which may occur when
cuttings containing small amounts of some of the synthetic materials
are discharged. Recently, these same commenters have endorsed the sheen
test as viable when using the synthetic-based drilling fluids. In
general, to pass the sheen test, the sample must be covered until below
the surface of the water, at which point it can be released. Samples of
synthetic-based drilling fluids may fail if stirred according to the
test method.

[[Page 66122]]

Conversely, samples have been shown to pass the static sheen test
following the addition of various levels of oil, crude oil, diesel oil,
and mineral oil in a laboratory controlled evaluation. Results of this
evaluation also showed that the sheen test appears to be more
subjective and difficult to judge for the synthetics than for the
water-based drilling fluids, due to the lack of dispersion of the
synthetics in the aqueous phase which leads to the question of adequate
stirring, and due to the formation of sheens (or discoloration) which
are not iridescent.
There is also concern with the ability of the static sheen test to
detect formation (crude) oil contamination on the cuttings when SBM is
used. Since these compounds consist of lipophilic matrices, any oily
(sheen producing) contaminants could dissolve in these matrices and be
brought to the sea floor with no observed sheen surface effect. Thus
the sheen test, which was developed to test for free oil contamination
in the oil or water-based drilling wastes, which readily disperse in
water, may not be appropriate. Formation oil contamination in certain
synthetic fluids has been shown to be clearly identifiable by using gas
chromatography (GC). Commenters have indicated that GC analysis with
flame ionization detection (GC/FID) can be practically performed at a
reasonable cost, and has in some instances been performed on offshore
platforms. GC/FID as described in method 1663 in document EPA 821-R-92-
008, ``Methods for the Determination of Diesel, Mineral, and Crude Oils
in Offshore Oil and Gas Industry Discharges,'' can be used to identify
the presence or increase of n-alkane groups from crude oil
contamination. Also contained in this document is high performance
liquid chromatography (HPLC) method 1654A, and the combination of
methods 1654A and 1663 can be used to differentiate diesel oil, mineral
oil, crude oil, and synthetic material. Gas chromatography followed in
series with mass spectroscopy (GC/MS) gives higher resolution and can
also be used to identify the presence of PAHs, but is also more
complicated and several times more expensive. Nonetheless, it may be
beneficial to perform GC/MS analysis to identify the PAHs. Free oil is
an indicator pollutant for PAHs. Several of the PAHs commonly found in
crude oil are priority pollutants.
In the United Kingdom and Norway, discharge requirements of SBM
drill cuttings follow the Oslo and Paris Commission (PARCOM) guidelines
for a harmonized chemical notification procedure. These guidelines
require drilling fluids to undergo marine toxicity, bioaccumulation and
biodegradation testing, and allow the regulatory authorities to
calculate the maximum amount of the fluid which can be expected not to
cause serious adverse environmental effects if lost or discharged to
the sea. The marine toxicity test evaluates both water-born and benthic
organisms such as algae (Skeletonema costatum), zooplankton (Acartia
tonsa), and amphipod crustacean sediment reworker (Corophium
volutator). EPA believes that tests such as these (or some combination
of these tests) may be more appropriate as the basis for both the
environmental assessment and for discharge limitations for the cuttings
associated with synthetic-based and EMO-based drilling fluids. Other
static sediment toxicity tests, such as the ASTM E1367-92, may also be
appropriate. Just recently detailed monitoring at several sites in the
North Sea has begun to evaluate seven different mud systems and to
compare the actual sea floor determinations with the laboratory
determinations. While evaluations in the Gulf of Mexico may prove to be
different from those in the North Sea due to the differences in
physical parameters and sea life, EPA intends to follow these sea floor
evaluations for early indications of appropriate laboratory and field
evaluation methods.
The final rule incorporates clarifying definitions of drilling
fluids for both the offshore and coastal subcategories to better
differentiate between the types of drilling fluids. At this time, EPA's
guidance to permit writers needing to write limits for SBMs on a best
professional judgement (BPJ) basis is to use GC as a confirmation tool
to assure the absence of free oil in addition to meeting the current no
free oil (static sheen), toxicity, and barite limits on mercury and
cadmium. Method 1663 as described in EPA 821-R-92-008 is recommended as
a GC/FID method to identify an increase in n-alkanes due to crude oil
contamination of the synthetic materials coating the cuttings to be
discharged. Additional tests such as benthic toxicity conducted on the
synthetic material prior to use or whole SBM prior to discharge, may be
useful in controlling the discharge of cuttings contaminated with
drilling fluid. One possible level of control is the use of the PARCOM
protocol for 1000 ppm acute benthic toxicity for Corophium volutator,
or similar protocol assessing a more appropriate local species as the
indicator.
EPA intends to further evaluate the test methods for benthic
toxicity and may determine an appropriate limitation if this additional
test is warranted. In addition, test methods and results for
bioaccumulation and biodegradation, as indications of the rate of
recovery of the cuttings piles on the sea floor, will be evaluated. It
is recognized that evaluations of such new testing protocols may be
beyond the technical expertise of individual permit writers. Thus this
effort will be coordinated as a continuing effluent guidelines effort.
Results of this effort may lead to revision of the current effluent
guidelines discharge limitations or may be useful in the revision or
reissuance of permits only.
One commenter claimed the same environmental advantages over WBM as
SBM with the use of enhanced mineral oil-based drilling fluids. EMO-
based drilling fluids are similar to the SBMs with respect to
dispersion in water and concerns with applicability of the current
sheen and toxicity tests. However, while the mysid shrimp water column
toxicity test may give comparable results for the EMOs and some
synthetics, several research papers indicate that recovery of cuttings
piles contaminated with low toxicity mineral oils may not be much
better than those contaminated with diesel, whereas those contaminated
by synthetic materials recover significantly faster. In the absence of
data on EMO contaminated cuttings and data indicating the differences
between low toxicity mineral oil and EMO, the application of limits on
the discharge of SBM cuttings according to the mysid shrimp toxicity
test and the static sheen test confirmed by GC test for no free oil, is
not applicable to the discharge of EMO cuttings. If the tests of
benthic toxicity, bioaccumulation, and biodegradation, which are
indicative of rate of recovery of the cuttings pile, show that the
performance of EMOs are acceptable, then they may be considered for
discharge of associated drilling fluids and cuttings. Another
complication with the use of EMO is that, since EMOs are not a specific
product as the synthetics are, but an assortment of molecules
conforming to the distillation cut, their gas chromatograph (GC)
fingerprint is in certain cases less distinct than that of the
synthetics. Contamination by formation oil, crude, or diesel, may be
more difficult to detect in these EMOs.

G. Implementation for NPDES Permit Writers

EPA received numerous comments from operators in the Gulf of Mexico

[[Page 66123]]

coastal region claiming that they would need additional time to comply
with the rule's zero discharge requirement for produced water. EPA
recognizes that it may take some time for operators to determine the
best and most cost effective mechanism of compliance and to implement
that mechanism. EPA also recognizes that the NPDES permit issuing
authority has discretion to use administrative orders to provide the
requisite additional time to meet zero discharge.
In making the determination regarding the additional time that may
be appropriate and interim requirements that will be placed on
facilities until compliance is achieved, the permit issuing authority
should consider several factors, including, but not limited to, the
following. First, operators may wish to do engineering and structural
analysis of existing pipes and wells in order to make use of existing
infra-structure. Second, there are several options available to
facilities on a per-well or per-facility basis to comply with the zero
discharge requirement, including injection, sending produced water
offsite to a centralized waste treatment facility, or shutting in
individual wells. Third, the facility's preferred approach may take
into consideration the projected productive life of individual wells
and their relative effect on the overall facility costs and impacts in
determining the most cost-effective mix of options. Fourth, the permit
issuing authority has the discretion to consider the relative impact of
the available options when determining an appropriate compliance
schedule. Finally, in establishing any interim limitations on
discharges, the permit issuing authority should consider water quality
impacts.

XV. Background Documents

Major support for this regulation is detailed in two documents,
each of which is supplemented by additional information and analyses in
the rulemaking record. EPA's engineering foundation for the regulation
is detailed in the ``Development Document for Final Effluent
Limitations Guidelines and Standards for the Coastal Subcategory of the
Oil and Gas Extraction Point Source Category'' EPA-821-R-96-023. EPA's
economic analysis is presented 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'' EPA-
821-R-96-022. Additionally, detailed responses to the public comments
received on the proposed regulation and notices of data availability
are presented in the document entitled ``Response to Public Comments on
Effluent Limitations Guidelines and Standards for the Coastal
Subcategory of the Oil and Gas Extraction Point Source Category,''
which is available in the public record. The public record for this
rulemaking is available for review at EPA's Water Docket; 401 M Street,
SW; Washington, DC. The room number is M2616 and the phone number is
(202) 260-3027.

List of Subjects in 40 CFR Part 435

Environmental protection, Incorporation by reference, Oil and gas
extraction, Pollution prevention, Waste treatment and disposal, Water
pollution control.

Dated: October 31, 1996.
Carol M. Browner,
Administrator.

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

Agency--U.S. Environmental Protection Agency
BADCT--The best available demonstrated control technology, for
new sources under section 306 of the CWA.
BAT--The best available technology economically achievable,
under section 304(b)(2)(B) of the CWA.

bbl--barrel, 42 U.S. gallons
bpd--barrels per day
bph--barrels per hour
bpy--barrels per year
BCT--Best conventional pollutant control technology under section
304(b)(4)(B).
BMPs--Best management practices under section 304(e) of the CWA.
BOD--Biochemical oxygen demand.
BOE--Barrels of oil equivalent
BPT--Best practicable control technology currently available, under
section 304(b)(1) of the Clean Water Act.
CFR--Code of Federal Regulations
Clean Water Act--Federal Water Pollution Control Act (33 U.S.C. 1251
et seq.).
Coastal Development Document--Development Document for Final
Effluent Limitations Guidelines and New Source Performance Standards
for the Coastal Subcategory Of the Oil and Gas Extraction Point
Source Category.
Conventional pollutants--Constituents of wastewater as determined by
section 304(a)(4) of the Act, including, but not limited to,
pollutants classified as biochemical oxygen demanding, suspended
solids, oil and grease, fecal coliform, and pH.
CWA--Clean Water Act
Direct discharger--A facility that discharges or may discharge
pollutants to waters of the United States.
DOE--U.S. Department of Energy
EIA--Economic Impact Analysis of Final Effluent Limitations
Guidelines and Standards for the Coastal Subcategory of the Oil and
Gas Extraction Point Source Category
EPA--U.S. Environmental Protection Agency
Indirect discharger--A facility that introduces wastewater into a
publicly owned treatment works.
LC50--The estimated concentration of a test material lethal to 50
percent of test organisms used in a specified type of toxicity test.
mg/l--milligrams per liter
Nonconventional pollutants--Pollutants that have not been designated
as either conventional pollutants or toxic pollutants.
NORM--Naturally Occurring Radioactive Materials
NPDES--The National Pollutant Discharge Elimination System under
section 402 of the CWA.
NPV--Net Present Value
NSPS--New source performance standards under section 306 of the CWA.
Offshore Guidelines--Final Effluent Limitations Guidelines and New
Source Performance Standards for the Offshore Subcategory of the Oil
and Gas Extraction Point Source Category
Offshore Development Document--Development Document for Effluent
Limitations Guidelines and New Source Performance Standards for the
Offshore Subcategory of the Oil and Gas Extraction Point Source
Category
OMB--Office of Management and Budget
PAH--polynuclear aromatic hydrocarbons
POTW--Publicly Owned Treatment Works
ppm--parts per million
PSES--Pretreatment standards for existing sources of indirect
discharges, under section 307(b) of the CWA.
PSNS--Pretreatment standards for new sources of indirect discharges,
under sections 307 (b) and (c) of the CWA.
RRC--Railroad Commission of Texas
SIC--Standard Industrial Classification
SPP--Suspended particulate phase.
Toxic pollutants--A statutory term for the 65 pollutants and classes
of pollutants designated under section 307(a) of the CWA.
TSS--Total Suspended Solids
UIC--Underground Injection Control program
U.S.C.--United States Code

For the reasons set forth in the preamble, 40 CFR part 435 is
amended as follows:

PART 435--OIL AND GAS EXTRACTION POINT SOURCE CATEGORY

1. The authority citation for part 435 continues to read as
follows:

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

Subpart A [Amended]

2. Section 435.10 is revised to read as follows:

Sec. 435.10 Applicability; description of the offshore subcategory

The provisions of this subpart are applicable to those facilities
engaged in

[[Page 66124]]

field exploration, drilling, well production, and well treatment in the
oil and gas industry which are located in waters that are seaward of
the inner boundary of the territorial seas (``offshore'') as defined in
section 502(g) of the Clean Water Act.
3. Section 435.11 is revised to read as follows:

Sec. 435.11 Specialized definitions.

For the purpose of this subpart:
(a) Except as provided below, the general definitions,
abbreviations and methods of analysis set forth in 40 CFR part 401
shall apply to this subpart.
(b) The term average of daily values for 30 consecutive days shall
be the average of the daily values obtained during any 30 consecutive
day period.
(c) The term daily values as applied to produced water effluent
limitations and NSPS shall refer to the daily measurements used to
assess compliance with the maximum for any one day.
(d) The term deck drainage shall refer to any waste resulting from
deck washings, spillage, rainwater, and runoff from gutters and drains
including drip pans and work areas within facilities subject to this
subpart. Within the definition of deck drainage for the purpose of this
subpart, the term rainwater for those facilities located on land is
limited to that precipitation runoff that reasonably has the potential
to come into contact with process wastewater. Runoff not included in
the deck drainage definition would be subject to control as storm water
under 40 CFR 122.26. For structures located over water, all runoff is
included in the deck drainage definition.
(e) The term development facility shall mean any fixed or mobile
structure subject to this subpart that is engaged in the drilling of
productive wells.
(f) The term diesel oil shall refer to the grade of distillate fuel
oil, as specified in the American Society for Testing and Materials
Standard Specification for Diesel Fuel Oils D975-91, that is typically
used as the continuous phase in conventional oil-based drilling fluids.
This incorporation by reference was approved by the Director of the
Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51.
Copies may be obtained from the American Society for Testing and
Materials, 1916 Race Street, Philadelphia, PA 19103. Copies may be
inspected at the Office of the Federal Register, 800 North Capitol
Street, NW., Suite 700, Washington, DC. A copy may also be inspected at
EPA's Water Docket; Room M2616, 401 M Street SW, Washington, DC 20460.
(g) The term domestic waste shall refer to materials discharged
from sinks, showers, laundries, safety showers, eye-wash stations,
hand-wash stations, fish cleaning stations, and galleys located within
facilities subject to this subpart.
(h) The term drill cuttings shall refer to the particles generated
by drilling into subsurface geologic formations and carried to the
surface with the drilling fluid.
(i) The term drilling fluid refers to the circulating fluid (mud)
used in the rotary drilling of wells to clean and condition the hole
and to counterbalance formation pressure. The four classes of drilling
fluids are:
(1) A water-based drilling fluid has water as the continuous phase
and the suspending medium for solids, whether or not oil is present.
(2) An oil-based drilling fluid has diesel oil, mineral oil, or
some other oil, but neither a synthetic material nor enhanced mineral
oil, as its continuous phase with water as the dispersed phase.
(3) An enhanced mineral oil-based drilling fluid has an enhanced
mineral oil as its continuous phase with water as the dispersed phase.
(4) A synthetic-based drilling fluid has a synthetic material as
its continuous phase with water as the dispersed phase.
(j) The term enhanced mineral oil as applied to enhanced mineral
oil-based drilling fluid means a petroleum distillate which has been
highly purified and is distinguished from diesel oil and conventional
mineral oil in having a lower polycyclic aromatic hydrocarbon (PAH)
content. Typically, conventional mineral oils have a PAH content on the
order of 0.35 weight percent expressed as phenanthrene, whereas
enhanced mineral oils typically have a PAH content of 0.001 or lower
weight percent PAH expressed as phenanthrene.
(k) The term exploratory facility shall mean any fixed or mobile
structure subject to this subpart that is engaged in the drilling of
wells to determine the nature of potential hydrocarbon reservoirs.
(l) The term maximum as applied to BAT effluent limitations and
NSPS for drilling fluids and drill cuttings shall mean the maximum
concentration allowed as measured in any single sample of the barite.
(m) The term maximum for any one day as applied to BPT, BCT and BAT
effluent limitations and NSPS for oil and grease in produced water
shall mean the maximum concentration allowed as measured by the average
of four grab samples collected over a 24-hour period that are analyzed
separately. Alternatively, for BAT and NSPS the maximum concentration
allowed may be determined on the basis of physical composition of the
four grab samples prior to a single analysis.
(n) The term minimum as applied to BAT effluent limitations and
NSPS for drilling fluids and drill cuttings shall mean the minimum 96-
hour LC50 value allowed as measured in any single sample of the
discharged waste stream. The term minimum as applied to BPT and BCT
effluent limitations and NSPS for sanitary wastes shall mean the
minimum concentration value allowed as measured in any single sample of
the discharged waste stream.
(o) The term M9IM shall mean those offshore facilities continuously
manned by nine (9) or fewer persons or only intermittently manned by
any number of persons.
(p) The term M10 shall mean those offshore facilities continuously
manned by ten (10) or more persons.
(q) The term new source means any facility or activity of this
subcategory that meets the definition of ``new source'' under 40 CFR
122.2 and meets the criteria for determination of new sources under 40
CFR 122.29(b) applied consistently with all of the following
definitions:
(1) The term water area as used in the term ``site'' in 40 CFR
122.29 and 122.2 shall mean the water area and ocean floor beneath any
exploratory, development, or production facility where such facility is
conducting its exploratory, development or production activities.
(2) The term significant site preparation work as used in 40 CFR
122.29 shall mean the process of surveying, clearing or preparing an
area of the ocean floor for the purpose of constructing or placing a
development or production facility on or over the site. ``New Source''
does not include facilities covered by an existing NPDES permit
immediately prior to the effective date of these guidelines pending EPA
issuance of a new source NPDES permit.
(r) The term no discharge of free oil shall mean that waste streams
may not be discharged when they would cause a film or sheen upon or a
discoloration of the surface of the receiving water or fail the static
sheen test defined in Appendix 1 to 40 CFR part 435, subpart A.
(s) The term produced sand shall refer to slurried particles used
in hydraulic fracturing, the accumulated formation sands and scales
particles generated during production.

[[Page 66125]]

Produced sand also includes desander discharge from the produced
water waste stream, and blowdown of the water phase from the produced
water treating system.
(t) The term produced water shall refer to the water (brine)
brought up from the hydrocarbon-bearing strata during the extraction of
oil and gas, and can include formation water, injection water, and any
chemicals added downhole or during the oil/water separation process.
(u) The term production facility shall mean any fixed or mobile
structure subject to this subpart that is either engaged in well
completion or used for active recovery of hydrocarbons from producing
formations.
(v) The term sanitary waste shall refer to human body waste
discharged from toilets and urinals located within facilities subject
to this subpart.
(w) The term static sheen test shall refer to the standard test
procedure that has been developed for this industrial subcategory for
the purpose of demonstrating compliance with the requirement of no
discharge of free oil. The methodology for performing the static sheen
test is presented in appendix 1 to 40 CFR part 435, subpart A.
(x) The term synthetic material as applied to synthetic-based
drilling fluid means material produced by the reaction of specific
purified chemical feedstock, as opposed to the traditional base fluids
such as diesel and mineral oil which are derived from crude oil solely
through physical separation processes. Physical separation processes
include fractionation and distillation and/or minor chemical reactions
such as cracking and hydro processing. Since they are synthesized by
the reaction of purified compounds, synthetic materials suitable for
use in drilling fluids are typically free of polycyclic aromatic
hydrocarbons (PAH's) but are sometimes found to contain levels of PAH
up to 0.001 weight percent PAH expressed as phenanthrene. Poly(alpha
olefins) and vegetable esters are two examples of synthetic materials
used by the oil and gas extraction industry in formulating drilling
fluids. Poly(alpha olefins) are synthesized from the polymerization
(dimerization, trimerization, tetramerization, and higher
oligomerization) of purified straight-chain hydrocarbons such as
C6-C14 alpha olefins. Vegetable esters are synthesized from
the acid-catalyzed esterification of vegetable fatty acids with various
alcohols. The mention of these two branches of synthetic fluid base
materials is to provide examples, and is not meant to exclude other
synthetic materials that are either in current use or may be used in
the future. A synthetic-based drilling fluid may include a combination
of synthetic materials.
(y) The term toxicity as applied to BAT effluent limitations and
NSPS for drilling fluids and drill cuttings shall refer to the bioassay
test procedure presented in Appendix 2 of 40 CFR part 435, subpart A.
(z) The term well completion fluids shall refer to salt solutions,
weighted brines, polymers, and various additives used to prevent damage
to the well bore during operations which prepare the drilled well for
hydrocarbon production.
(aa) The term well treatment fluids shall refer to any fluid used
to restore or improve productivity by chemically or physically altering
hydrocarbon-bearing strata after a well has been drilled.
(bb) The term workover fluids shall refer to salt solutions,
weighted brines, polymers, or other specialty additives used in a
producing well to allow for maintenance, repair or abandonment
procedures.
(cc) The term 96-hour LC50 shall refer to the concentration (parts
per million) or percent of the suspended particulate phase (SPP) from a
sample that is lethal to 50 percent of the test organisms exposed to
that concentration of the SPP after 96 hours of constant exposure.
4. Subpart D is revised to read as follows:

Subpart D--Coastal Subcategory

Sec.
435.40 Applicability; description of the coastal subcategory.
435.41 Specialized definitions.
435.42 Effluent limitations guidelines representing the degree of
effluent reduction attainable by the application of the best
practicable control technology currently available (BPT).
435.43 Effluent limitations guidelines representing the degree of
effluent reduction attainable by the application of the best
available technology economically achievable (BAT).
435.44 Effluent limitations guidelines representing the degree of
effluent reduction attainable by the application of the best
conventional pollutant control technology (BCT).
435.45 Standards of performance for new sources (NSPS).
435.46 Pretreatment Standards of performance for existing sources
(PSES).
435.47 Pretreatment Standards of performance for new sources
(PSNS).

Subpart D--Coastal Subcategory

Sec. 435.40 Applicability; description of the coastal subcategory.

The provisions of this subpart are applicable to those facilities
engaged in field exploration, drilling, well production, and well
treatment in the oil and gas industry in areas defined as ``coastal.''
The term ``coastal'' shall mean:
(a) Any location in or on a water of the United States landward of
the inner boundary of the territorial seas; or
(b) (1) Any location landward from the inner boundary of the
territorial seas and bounded on the inland side by the line defined by
the inner boundary of the territorial seas eastward of the point
defined by 89 deg.45' West Longitude and 29 deg.46' North Latitude and
continuing as follows west of that point:

------------------------------------------------------------------------
Direction to west longitude Direction to north latitude
------------------------------------------------------------------------
West, 89 deg.48'.......................... North, 29 deg.50'.
West, 90 deg.12'.......................... North, 30 deg.06'.
West, 90 deg.20'.......................... South, 29 deg.35'.
West, 90 deg.35'.......................... South, 29 deg.30'.
West, 90 deg.43'.......................... South, 29 deg.25'.
West, 90 deg.57'.......................... North, 29 deg.32'.
West, 91 deg.02'.......................... North, 29 deg.40'.
West, 91 deg.14'.......................... South, 29 deg.32'.
West, 91 deg.27'.......................... North, 29 deg.37'.
West, 91 deg.33'.......................... North, 29 deg.46'.
West, 91 deg.46'.......................... North, 29 deg.50'.
West, 91 deg.50'.......................... North, 29 deg.55'.
West, 91 deg.56'.......................... South, 29 deg.50'.
West, 92 deg.10'.......................... South, 29 deg.44'.
West, 92 deg.55'.......................... North, 29 deg.46'.
West, 93 deg.15'.......................... North, 30 deg.14'.
West, 93 deg.49'.......................... South, 30 deg.07'.
West, 94 deg.03'.......................... South, 30 deg.03'.
West, 94 deg.10'.......................... South, 30 deg.00'.
West, 94 deg.20'.......................... South, 29 deg.53'.
West, 95 deg.00'.......................... South, 29 deg.35'.
West, 95 deg.13'.......................... South, 29 deg.28'.
East, 95 deg.08'.......................... South, 29 deg.15'.
West, 95 deg.11'.......................... South, 29 deg.08'.
West, 95 deg.22'.......................... South, 28 deg.56'.
West, 95 deg.30'.......................... South, 28 deg.55'.
West, 95 deg.33'.......................... South, 28 deg.49'.
West, 95 deg.40'.......................... South, 28 deg.47'.
West, 96 deg.42'.......................... South, 28 deg.41'.
East, 96 deg.40'.......................... South, 28 deg.28'.
West, 96 deg.54'.......................... South, 28 deg.20'.
West, 97 deg.03'.......................... South, 28 deg.13'.
West, 97 deg.15'.......................... South, 27 deg.58'.
West, 97 deg.40'.......................... South, 27 deg.45'.
West, 97 deg.46'.......................... South, 27 deg.28'.
West, 97 deg.51'.......................... South, 27 deg.22'.
East, 97 deg.46'.......................... South, 27 deg.14'.
East, 97 deg.30'.......................... South, 26 deg.30'.
East, 97 deg.26'.......................... South, 26 deg.11'.
------------------------------------------------------------------------

(2) East to 97 deg.19' West Longitude and Southward to the U.S.-
Mexican border.

Sec. 435.41 Specialized definitions.

For the purpose of this subpart:
(a) Except as provided below, the general definitions,
abbreviations and

[[Page 66126]]

methods of analysis set forth in 40 CFR part 401 shall apply to this
subpart.
(b) The term average of daily values for 30 consecutive days shall
be the average of the daily values obtained during any 30 consecutive
day period.
(c) The term ``Cook Inlet'' refers to coastal locations north of
the line between Cape Douglas on the West and Port Chatham on the east.
(d) The term daily values as applied to produced water effluent
limitations and NSPS shall refer to the daily measurements used to
assess compliance with the maximum for any one day.
(e) The term deck drainage shall refer to any waste resulting from
deck washings, spillage, rainwater, and runoff from gutters and drains
including drip pans and work areas within facilities subject to this
subpart.
(f) The term development facility shall mean any fixed or mobile
structure subject to this subpart that is engaged in the drilling of
productive wells.
(g) The term dewatering effluent means wastewater from drilling
fluids and drill cuttings dewatering activities (including but not
limited to reserve pits or other tanks or vessels, and chemical or
mechanical treatment occurring during the drilling solids separation/
recycle/disposal process).
(h) The term diesel oil shall refer to the grade of distillate fuel
oil, as specified in the American Society for Testing and Materials
Standard Specification for Diesel Fuel Oils D975-91, that is typically
used as the continuous phase in conventional oil-based drilling fluids.
This incorporation by reference was approved by the Director of the
Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51.
Copies may be obtained from the American Society for Testing and
Materials, 1916 Race Street, Philadelphia, PA 19103. Copies may be
inspected at the Office of the Federal Register, 800 North Capitol
Street, NW., Suite 700, Washington, DC. A copy may also be inspected at
EPA's Water Docket; Room M2616, 401 M Street SW., Washington, DC 20460.
(i) The term domestic waste shall refer to materials discharged
from sinks, showers, laundries, safety showers, eye-wash stations,
hand-wash stations, fish cleaning stations, and galleys located within
facilities subject to this subpart.
(j) The term drill cuttings shall refer to the particles generated
by drilling into subsurface geologic formations and carried to the
surface with the drilling fluid.
(k) The term drilling fluid refers to the circulating fluid (mud)
used in the rotary drilling of wells to clean and condition the hole
and to counterbalance formation pressure. The four classes of drilling
fluids are:
(1) A water-based drilling fluid has water as the continuous phase
and the suspending medium for solids, whether or not oil is present.
(2) An oil-based drilling fluid has diesel oil, mineral oil, or
some other oil, but neither a synthetic material nor enhanced mineral
oil, as its continuous phase with water as the dispersed phase.
(3) An enhanced mineral oil-based drilling fluid has an enhanced
mineral oil as its continuous phase with water as the dispersed phase.
(4) A synthetic-based drilling fluid has a synthetic material as
its continuous phase with water as the dispersed phase.
(l) The term enhanced mineral oil as applied to enhanced mineral
oil-based drilling fluid means a petroleum distillate which has been
highly purified and is distinguished from diesel oil and conventional
mineral oil in having a lower polycyclic aromatic hydrocarbon (PAH)
content. Typically, conventional mineral oils have a PAH content on the
order of 0.35 weight percent expressed as phenanthrene, whereas
enhanced mineral oils typically have a PAH content of 0.001 or lower
weight percent PAH expressed as phenanthrene.
(m) The term exploratory facility shall mean any fixed or mobile
structure subject to this subpart that is engaged in the drilling of
wells to determine the nature of potential hydrocarbon reservoirs.
(n) The term garbage means all kinds of victual, domestic, and
operational waste, excluding fresh fish and parts thereof, generated
during the normal operation of coastal oil and gas facility and liable
to be disposed of continuously or periodically, except dishwater,
graywater, and those substances that are defined or listed in other
Annexes to MARPOL 73/78. A copy of MARPOL may be inspected at EPA's
Water Docket; Room M2616, 401 M Street SW, Washington, DC 20460.
(o) The term maximum as applied to BAT effluent limitations and
NSPS for drilling fluids and drill cuttings shall mean the maximum
concentration allowed as measured in any single sample of the barite.
(p) The term maximum for any one day as applied to BPT, BCT and BAT
effluent limitations and NSPS for oil and grease in produced water
shall mean the maximum concentration allowed as measured by the average
of four grab samples collected over a 24-hour period that are analyzed
separately. Alternatively, for BAT and NSPS, the maximum concentration
allowed may be determined on the basis of physical composition of the
four grab samples prior to a single analysis.
(q) The term minimum as applied to BAT effluent limitations and
NSPS for drilling fluids and drill cuttings shall mean the minimum 96-
hour LC50 value allowed as measured in any single sample of the
discharged waste stream. The term minimum as applied to BPT and BCT
effluent limitations and NSPS for sanitary wastes shall mean the
minimum concentration value allowed as measured in any single sample of
the discharged waste stream.
(r) The term M9IM shall mean those coastal facilities continuously
manned by nine (9) or fewer persons or only intermittently manned by
any number of persons.
(s) The term M10 shall mean those coastal facilities continuously
manned by ten (10) or more persons.
(t) (1) The term new source means any facility or activity of this
subcategory that meets the definition of ``new source'' under 40 CFR
122.2 and meets the criteria for determination of new sources under 40
CFR 122.29(b) applied consistently with all of the following
definitions:
(i) The term water area as used in the term ``site'' in 40 CFR
122.29 and 122.2 shall mean the water area and water body floor beneath
any exploratory, development, or production facility where such
facility is conducting its exploratory, development or production
activities.
(ii) The term significant site preparation work as used in 40 CFR
122.29 shall mean the process of surveying, clearing or preparing an
area of the water body floor for the purpose of constructing or placing
a development or production facility on or over the site.
(2) ``New Source'' does not include facilities covered by an
existing NPDES permit immediately prior to the effective date of these
guidelines pending EPA issuance of a new source NPDES permit.
(u) The term no discharge of free oil shall mean that waste streams
may not be discharged when they would cause a film or sheen upon or a
discoloration of the surface of the receiving water or fail the static
sheen test defined in appendix 1 to 40 CFR part 435, subpart A.
(v) The term produced sand shall refer to slurried particles used
in hydraulic fracturing, the accumulated formation sands and scales
particles generated during production. Produced sand also includes
desander discharge from the produced water waste stream,

[[Page 66127]]

and blowdown of the water phase from the produced water treating
system.
(w) The term produced water shall refer to the water (brine)
brought up from the hydrocarbon-bearing strata during the extraction of
oil and gas, and can include formation water, injection water, and any
chemicals added downhole or during the oil/water separation process.
(x) The term production facility shall mean any fixed or mobile
structure subject to this subpart that is either engaged in well
completion or used for active recovery of hydrocarbons from producing
formations. It includes facilities that are engaged in hydrocarbon
fluids separation even if located separately from wellheads.
(y) The term sanitary waste shall refer to human body waste
discharged from toilets and urinals located within facilities subject
to this subpart.
(y) The term static sheen test shall refer to the standard test
procedure that has been developed for this industrial subcategory for
the purpose of demonstrating compliance with the requirement of no
discharge of free oil. The methodology for performing the static sheen
test is presented in appendix 1 to 40 CFR part 435, subpart A.
(z) The term synthetic material as applied to synthetic-based
drilling fluid means material produced by the reaction of specific
purified chemical feedstock, as opposed to the traditional base fluids
such as diesel and mineral oil which are derived from crude oil solely
through physical separation processes. Physical separation processes
include fractionation and distillation and/or minor chemical reactions
such as cracking and hydro processing. Since they are synthesized by
the reaction of purified compounds, synthetic materials suitable for
use in drilling fluids are typically free of polycyclic aromatic
hydrocarbons (PAH's) but are sometimes found to contain levels of PAH
up to 0.001 weight percent PAH expressed as phenanthrene. Poly(alpha
olefins) and vegetable esters are two examples of synthetic used by the
oil and gas extraction industry in formulating drilling fluids.
Poly(alpha olefins) are synthesized from the polymerization
(dimerization, trimerization, tetramerization, and higher
oligomerization) of purified straight-chain hydrocarbons such as
C6-C14 alpha olefins. Vegetable esters are synthesized from
the acid-catalyzed esterification of vegetable fatty acids with various
alcohols. The mention of these two branches of synthetic fluid base
materials is to provide examples, and is not meant to exclude other
synthetic materials that are either in current use or may be used in
the future. A synthetic-based drilling fluid may include a combination
of synthetic materials.
(aa) The term toxicity as applied to BAT effluent limitations and
NSPS for drilling fluids and drill cuttings shall refer to the bioassay
test procedure presented in appendix 2 of 40 CFR part 435, subpart A.
(bb) The term well completion fluids shall refer to salt solutions,
weighted brines, polymers, and various additives used to prevent damage
to the well bore during operations which prepare the drilled well for
hydrocarbon production.
(cc) The term well treatment fluids shall refer to any fluid used
to restore or improve productivity by chemically or physically altering
hydrocarbon-bearing strata after a well has been drilled.
(dd) The term workover fluids shall refer to salt solutions,
weighted brines, polymers, or other specialty additives used in a
producing well to allow for maintenance, repair or abandonment
procedures.
(ee) The term 96-hour LC50 shall refer to the concentration (parts
per million) or percent of the suspended particulate phase (SPP) from a
sample that is lethal to 50 percent of the test organisms exposed to
that concentration of the SPP after 96 hours of constant exposure.

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

Except as provided in 40 CFR 125.30-125.32, any existing point
source subject to this Subpart must achieve the following effluent
limitations representing the degree of effluent reduction attainable by
the application of the best practicable control technology currently
available.

BPT Effluent Limitations--Oil and Grease
[In milligrams per liter]
----------------------------------------------------------------------------------------------------------------
Residual
Average of values for 30 chlorine
Pollutant parameter waste source Maximum for any 1 day consecutive days shall not minimum for
exceed any 1 day
----------------------------------------------------------------------------------------------------------------
Produced water........................ 72........................... 48.......................... NA
Deck drainage......................... (\1\)........................ (\1\)....................... NA
Drilling fluid........................ (\1\)........................ (\1\)....................... NA
Drill cuttings........................ (\1\)........................ (\1\)....................... NA
Well treatment, workover, and (\1\)........................ (\1\)....................... NA
completion fluids.
Sanitary:
M10............................... NA........................... NA.......................... \2\ 1
M9IM \3\.......................... NA........................... NA.......................... NA
Domestic \3\...................... NA........................... NA.......................... NA
Produced sand..................... Zero discharge............... Zero discharge.............. NA
----------------------------------------------------------------------------------------------------------------
\1\ No discharge of free oil.
\2\ Minimum of 1 mg/l and maintained as close to this concentration as possible.
\3\ There shall be no floating solids as a result of the discharge of these wastes.

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

Except as provided in 40 CFR 125.30-125.32, any existing point
source subject to this Subpart must achieve the following effluent
limitations representing the degree of effluent reduction attainable by
the application of the best available technology economically
achievable (BAT):

[[Page 66128]]

BAT Effluent Limitations
------------------------------------------------------------------------
Pollutant BAT effluent
Stream parameter limitations
------------------------------------------------------------------------
Produced Water:
(A) All coastal areas except .................. No discharge.
Cook Inlet.
(B) Cook Inlet.............. Oil & Grease...... The maximum for
any one day shall
not exceed 42 mg/
l, and the 30-day
average shall not
exceed 29 mg/l.
Drilling Fluids, Drill Cuttings,
and Dewatering Effluent: \1\
(A) All coastal areas except .................. No discharge.
Cook Inlet.
Free Oil \2\...... No discharge.
Diesel Oil........ No discharge.
(B) Cook Inlet.............. Mercury........... 1 mg/kg dry weight
maximum in the
stock barite.
Cadmium........... 3 mg/kg dry weight
maximum in the
stock barite.
Toxicity.......... Minimum 96-hour
LC50 of the SPP
shall be 3
percent by volume
\4\.
Well Treatment, Workover and
Completion Fluids:
(A) All coastal areas except .................. No discharge.
Cook Inlet.
(B) Cook Inlet.............. Oil and Grease.... The maximum for
any one day shall
not exceed 42 mg/
l, and the 30-day
average shall not
exceed 29 mg/l.
Produced Sand............... .................. No discharge.
Deck Drainage............... Free Oil \3\...... No discharge.
Domestic Waste.............. Foam.............. No discharge.
------------------------------------------------------------------------
\1\ BCT limitations for dewatering effluent are applicable
prospectively. BCT limitations in this rule are not applicable to
discharges of dewatering effluent from reserve pits which as of the
effective date of this rule no longer receive drilling fluids and
drill cuttings. Limitations on such discharges shall be determined by
the NPDES permit issuing authority.
\2\ As determined by the static sheen test (see appendix 1 to 40 CFR
part 435, subpart A).
\3\ As determined by the presence of a film or sheen upon or a
discoloration of the surface of the receiving water (visual sheen).
\4\ As determined by the toxicity test (see appendix 2 of 40 CFR part
435, subpart A).

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

BCT Effluent Limitations
------------------------------------------------------------------------
Pollutant BCT effluent
Stream parameter limitations
------------------------------------------------------------------------
Produced Water (all facilities). Oil & Grease...... The maximum for
any one day shall
not exceed 72 mg/
l and the 30-day
average shall not
exceed 48 mg/l.
Drilling Fluids and Drill
Cuttings and Dewatering
Effluent:\1\
All facilities except Cook .................. No discharge.
Inlet.
Cook Inlet.................. Free Oil.......... No discharge.\2\
Well Treatment, Workover and Free Oil.......... No discharge.\2\
Completion Fluids.
Produced Sand................... .................. No discharge.
Deck Drainage................... Free Oil.......... No discharge.\3\
Sanitary Waste:
Sanitary M10................ Residual Chlorine. Minimum of 1 mg/l
maintained as
close to this
concentration as
possible.
Sanitary M91M............... Floating Solids... No discharge.
Domestic Waste.................. Floating Solids No discharge of
and garbage. Floating Solids
or garbage.\4\
------------------------------------------------------------------------
\1\ BCT limitations for dewatering effluent are applicable
prospectively. BCT limitations in this rule are not applicable to
discharges of dewatering effluent from reserve pits which as of the
effective date of this rule no longer receive drilling fluids and
drill cuttings. Limitations on such discharges shall be determined by
the NPDES permit issuing authority.
\2\ As determined by the static sheen test (see appendix 1 to 40 CFR
part 435, subpart A).
\3\ As determined by the presence of a film or sheen upon or a
discoloration of the surface of the receiving water (visual sheen).
\4\ As determined by the toxicity test (see appendix 2 of 40 CFR part
435, subpart A).

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

Any new source subject to this subpart must achieve the following
new source performance standards (NSPS):

[[Page 66129]]

NSPS Effluent Limitations
------------------------------------------------------------------------
Pollutant NSPS effluent
Stream parameter limitations
------------------------------------------------------------------------
Produced Water (all facilities). .................. No discharge.
Drilling Fluids and Drill
Cuttings and Dewatering
Effluent: \1\
(A) All coastal areas except .................. No discharge.
Cook Inlet.
(B) Cook Inlet.............. Free Oil \1\...... No discharge.
Diesel Oil........ No discharge.
Mercury........... 1 mg/kg dry weight
maximum in the
stock barite; 3
mg/kg dry weight
maximum in the
stock barite.
Cadmium........... Minimum 96-hour
LC50 of the SPP
shall be 3
percent by
volume.\3\
Toxicity..........
Well Treatment, Workover and
Completion Fluids:
(A) All coastal areas except .................. No discharge.
Cook Inlet.
(B) Cook Inlet.............. Oil and Grease.... The maximum for
any one day shall
not exceed 42 mg/
l, and the 30-day
average shall not
exceed 29 mg/l.
Produced Sand................... .................. No discharge.
Deck Drainage................... Free Oil \2\...... No discharge.
Sanitary Waste:
Sanitary M10................ Residual Chlorine. Minimum of 1 mg/l
and maintained as
close to this
concentration as
possible.
Sanitary M91M............... Floating Solids... No discharge.
Domestic Waste.................. Floating Solids, No discharge of
Garbage \4\ and floating solids
Foam. or garbage or
foam.
------------------------------------------------------------------------
\1\ BAT limitations for dewatering effluent are applicable
prospectively. BAT limitations in this rule are not applicable to
discharges of dewatering effluent from reserve pits which as of the
effective date of this rule no longer receive drilling fluids and
drill cuttings. Limitations on such discharges shall be determined by
the NPDES permit issuing authority.
\2\ As determined by the static sheen test (see Appendix 1 to 40 CFR
part 435, subpart A).
\3\ As determined by the presence of a film or sheen upon or a
discoloration of the surface of the receiving water (visual sheen).
\4\ As determined by the toxicity test (see Appendix 2 of 40 CFR part
435, subpart A).
\5\ As defined in 40 CFR 435.41(1).

Sec. 435.46 Pretreatment Standards of Performance for Existing Sources
(PSES)

Except as provided in 40 CFR 403.7 and 403.13, any existing source
with discharges subject to this subpart that introduces pollutants into
a publicly owned treatment works must comply with 40 CFR part 403 and
achieve the following pretreatment standards for existing sources
(PSES).

PSES Effluent Limitations
------------------------------------------------------------------------
Pollutant PSES effluent
Stream parameter limitations
------------------------------------------------------------------------
Produced Water.................. ............... No discharge.
Drilling Fluids and Drill
Cuttings Well Treatment.
Workover and Completion Fluids.. ............... No discharge.
Produced Sand................... ............... No discharge.
Deck Drainage................... ............... No discharge.
------------------------------------------------------------------------

Sec. 435.47 Pretreatment Standards of performance for new sources
(PSNS)

Except as provided in 40 CFR 403.7 and 403.13, any new source with
discharges subject to this subpart that introduces pollutants into a
publicly owned treatment works must comply with 40 CFR part 403 and
achieve the following pretreatment standards for new sources (PSNS).

PSNS Effluent Limitations
------------------------------------------------------------------------
Pollutant PSNS effluent
Stream parameter limitations
------------------------------------------------------------------------
Produced Water (all facilities). .................. No discharge.
Drilling fluids and Drill .................. No discharge.
Cuttings.
Well Treatment, Workover and .................. No discharge.
Completion Fluids.
Produced Sand................... .................. No discharge.
Deck Drainage................... .................. No discharge.
------------------------------------------------------------------------

5. Subpart G consisting of Sec. 435.10 is added to read as follows:

Subpart G--General Provisions

Sec. 435.10 Applicability.

(a) Purpose. This subpart is intended to prevent oil and gas
facilities, for which effluent limitations guidelines and standards,
new source performance standards, or pretreatment standards have been
promulgated under this part, from circumventing the effluent
limitations guidelines and standards applicable to those facilities by
moving effluent produced in one subcategory to another subcategory for
disposal under less stringent requirements than intended by this part.
(b) Applicability. The effluent limitations and standards
applicable to an oil and gas facility shall be determined as follows:
(1) An Oil and Gas facility, operator, or its agent or contractor
may move its wastewaters from a facility located in one subcategory to
another subcategory for treatment and return it to a location covered
by the original subcategory for disposal. In such case, the effluent
limitations guidelines, new source performance standards, or
pretreatment standards for the original subcategory apply.
(2) An Oil and Gas facility, operator, or its agent or contractor
may move its wastewaters from a facility located in one subcategory to
another subcategory for disposal or treatment and disposal, provided:
(i) If an Oil and Gas facility, operator or its agent or contractor
moves

[[Page 66130]]

wastewaters from a wellhead located in one subcategory to another
subcategory where oil and gas facilities are governed by less stringent
effluent limitations guidelines, new source performance standards, or
pretreatment standards, the more stringent effluent limitations
guidelines, new source performance standards, or pretreatment standards
applicable to the subcategory where the wellhead is located shall
apply.
(ii) If an Oil and Gas facility, operator or its agent moves
effluent from a wellhead located in one subcategory to another
subcategory where oil and gas facilities are governed by more stringent
effluent limitations guidelines, new source performance standards, or
pretreatment standards, the more stringent effluent limitations
guidelines, new source performance standards, or pretreatment standards
applicable at the point of discharge shall apply.

[FR Doc. 96-28659 Filed 12-13-96; 8:45 am]
BILLING CODE 6560-50-P}}}}}}}}}}}}}}}}}}}}}}}}}}}}}}}}}}