[Federal Register Volume 60, Number 33 (Friday, February 17, 1995)]
[Proposed Rules]
[Pages 9428-9481]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 95-3602]




[[Page 9427]]

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Part II





Environmental Protection Agency





_______________________________________________________________________



40 CFR Part 435



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

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

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 435

[FRL-5149-7]
RIN 2040-AB72


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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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

SUMMARY: This proposed regulation would limit the discharge of 
pollutants into waters of the United States and the introduction of 
pollutants into publicly-owned treatment works by existing and new 
facilities in the coastal subcategory of the oil and gas extraction 
point source category.
    This proposed regulation would establish effluent limitations 
guidelines and new source performance standards (NSPS) for direct 
dischargers based on ``best practicable control technology currently 
available'' (BPT), ``best conventional pollutant control technology'' 
(BCT), ``best available technology economically achievable'' (BAT), and 
``best available demonstrated control technology'' (BADCT) for new 
sources. The proposal also would establish ``pretreatment standards for 
new sources'' (PSNS) and ``pretreatment standards for existing 
sources'' (PSES) for facilities discharging their wastewaters to 
publicly-owned treatment works (POTWs).
    This regulation will reduce the discharge of pollutants into U.S. 
coastal water bodies by 4.3 billion pounds, thereby also reducing the 
impacts these discharges would otherwise incur to aquatic life and/or 
human health. As a result of consultation with stakeholders, the 
preamble solicits comments and data not only on issues raised by EPA, 
but also on those raised by State and local governments who will be 
implementing these regulations and by industry representatives who will 
be affected by them.
    This proposal does not take into account the regulatory effects of 
the recently published final EPA Region VI NPDES General Permits for 
production facilities (January 9, 1995). With these permits in effect, 
the costs of this proposal will be reduced and the actual reduction of 
pollutant loadings to coastal waters would be approximately 71 percent 
less, or 1.25 billion pounds per year, due to today's proposal. EPA 
will more fully incorporate the regulatory effects of the Region VI 
General Permits upon promulgation of the final rule.

DATES: Comments on the proposal must be received by May 18, 1995. Two 
public meetings will be held during the comment period: on March 7, 
1995, in New Orleans, Louisiana and on March 21, 1995, in Seattle, 
Washington. Both meetings will be held from 9:00 am to 12:00 pm.

ADDRESSES: Submit comments in writing to: Ms. Allison Wiedeman, 
Engineering and Analysis Division (4303), U.S. EPA, 401 M Street, S.W., 
Washington, DC 20460. Please submit any references cited in your 
comments. EPA would appreciate an original and two copies of your 
comments and enclosures (including references).
    The public record supporting the proposed effluent limitations 
guidelines and standards is in the Water Docket located in the basement 
of the EPA Headquarters building, Room L102, 401 M Street S.W., 
Washington, DC 20460. For access to Docket materials call (202) 260-
3027. The Docket staff requests that interested parties call, between 
9:00 am and 3:30 pm, for an appointment before visiting the docket. The 
EPA regulations at 40 CFR Part 2 provide that a reasonable fee may be 
charged for copying.
    The workshops covering the rulemaking will be held at the Minerals 
Management Service, Gulf of Mexico OCS Region, Office of the Regional 
Director, 1201 Elmwood Park Boulevard in New Orleans, Louisiana on 
March 7, 1995, and at the Federal Building, 915 2nd Avenue, North 
Auditorium in Seattle, Washington on March 21, 1995.
    The background documents are available from the Office of Water 
Resource Center, RC-4100, at the U.S. EPA, Washington, DC address shown 
above; telephone (202) 260-7786 for the voice mail publication request 
line.

FOR FURTHER INFORMATION CONTACT: For technical information contact Ms. 
Allison Wiedeman at (202) 260-7179. For economic information contact 
Dr. Matthew Clark at (202) 260-7192.

SUPPLEMENTARY INFORMATION:

Public Meeting

    No meeting materials will be distributed in advance of these 
meetings: all material will be distributed at the meetings. See 
ADDRESSES for information on location of the public meetings.

Docket
    EPA notes that many documents in the record supporting these 
proposed rules have been claimed as confidential business information 
(CBI) and, therefore, are not included in the record that is available 
to the public in the Water Docket. To support the rulemaking, EPA is 
presenting certain information in aggregated form or is masking 
facility identities to preserve confidentiality claims. Further, the 
Agency has withheld from disclosure some data not claimed as 
confidential business information because release of this information 
could indirectly reveal information claimed to be confidential.
    Some facility-specific data, which have been claimed as 
confidential business information, are available to the company that 
submitted the information. To ensure that all CBI is protected in 
accordance with EPA regulations, any requests for company-specific data 
should be submitted to EPA on company letterhead and signed by a 
responsible official authorized to receive such data. The request must 
list the specific data requested and include the following statement, 
``I certify that EPA is authorized to transfer confidential business 
information submitted by my company, and that I am authorized to 
receive it.''

Overview

    This preamble includes a description of the legal authority for 
these rules; a summary of the proposal; a description of the background 
documents that support these proposed regulations and other background 
information; and a description of the technical and economic 
methodologies used by EPA to develop these regulations. This preamble 
also solicits comment and data on specific areas of interest. The 
definitions, acronyms, and abbreviations used in this notice are 
defined in Appendix A to the preamble.

Organization of This Document

I. Legal Authority
II. Summary and Scope of the Proposed Regulations
    A. Purpose of this Rulemaking
    B. Summary of Proposed Coastal Guidelines
    C. The EPA Region VI Coastal Oil and Gas Production NPDES 
General Permit
    D. Preventing the Circumvention of Effluent Limitations 
Guidelines and New Source Performance Standards
    E. Common Sense Initiative
III. Background
    A. Clean Water Act
    B. Pollution Prevention Act
    C. Coastal Subcategory Definition
    D. New Source Definition
    E. Summary of Public Participation
IV. Description of the Industry
    A. Industry Description
    B. Location
    C. Activity [[Page 9429]] 
    D. Waste Streams
    E. Current NPDES Permits
V. Summary of Data Gathering Efforts
    A. Information Used From the Offshore Guidelines
    B. 1993 Coastal Oil and Gas Questionnaire
    C. Investigation of Solids Control Technologies for Drilling 
Fluids
    D. Sampling Visits to 10 Gulf of Mexico Coastal Production 
Facilities
    E. State Discharge Monitoring Reports
    F. Commercial Disposal Operations
    G. Evaluation of NORM in Produced Waters
    H. Alaska Operations
    I. Region X Drilling Fluid Toxicity Data Study
    J. California Operations
    K. OSW Sampling Program
    L. Estimation of the Inner Boundary of the Territorial Seas
. VI. Development of Effluent Limitations Guidelines and Standards
    A. Drilling Fluids and Drill Cuttings (Drilling Wastes)
    B. Produced Water
    C. Produced Sand
    D. Deck Drainage
    E. Treatment, Workover, and Completion Fluids
    F. Domestic Wastes
    G. Sanitary Wastes
VII. Economic Analysis
    A. Introduction
    B. Economic Methodology
    C. Summary of Costs and Economic Impacts
    D. Produced Water
    E. Drilling Fluids and Drill Cuttings
    F. Treatment, Workover, and Completion Fluids
    G. Cost-Effectiveness Analysis
    H. Regulatory Flexibility
VIII. Non Water Quality Environmental Impacts
    A. Drilling Fluids and Cuttings
    B. Produced Water
    C. Treatment, Workover and Completion Fluids
IX. Executive Order 12866
X. Executive Order 12875
XI. Paperwork Reduction Act
XII. Environmental Benefits Analysis
    A. Introduction
    B. Quantitative Estimate of Benefits
    C. Description of Non-Quantified Benefits
    D. EPA Region VI Production Permit
XIII. Regulatory Implementation
    A. Toxicity Limitation for Drilling Fluids and Drill Cuttings
    B. Diesel Prohibition for Drilling Fluids and Drill Cuttings
    C. Upset and Bypass Provisions
    D. Variances and Modifications
    E. Synthetic Drilling Fluids
XIV. Related Rulemakings
XV. Solicitation of Data and Comments
XVI. Background Documents
Appendix A--Abbreviations, Acronyms, and Other Terms Used in This 
Notice

I. Legal Authority

    These regulations are being proposed under the authority of 
sections 301, 304, 306, 307, 308, and 501 of the Clean Water Act (CWA), 
33 U.S.C. sections 1311, 1314, 1316, 1317, 1318, and 1361.

II. Summary and Scope of the Proposed Regulations

A. Purpose of This Rulemaking

    The purpose of this rulemaking is to propose effluent limitations 
guidelines and standards for the control of the discharge of pollutants 
for the Coastal Subcategory of the Oil and Gas Extraction Point Source 
Category. The discharge limitations proposed today apply to discharges 
from coastal oil and gas extraction facilities, including exploration, 
development and production operations. The processes and operations 
which comprise the coastal oil and gas subcategory (Standard Industrial 
Classification (SIC) Major Group 13) are currently regulated under 40 
CFR Part 435, Subpart D. These regulations are being proposed under the 
authority of the CWA, as discussed in Section I of this notice. The 
regulations are also being proposed pursuant to a Consent Decree 
entered in NRDC et al. v. Reilly, (D D.C. No. 89-2980, January 31, 
1992) and are consistent with EPA's latest Effluent Guidelines Plan 
under section 304(m) of the CWA. (See 59 FR 44234, August 26, 1994). 
The existing effluent limitations guidelines, which were issued on 
April 13, 1979 (44 FR 22069), are based on the achievement of best 
practicable control technology currently available (BPT). This proposed 
rule is referred to as the Coastal Guidelines throughout this preamble.
    This summary section highlights key aspects of the proposed rule. 
The technology descriptions discussed later in this notice are 
presented in abbreviated form; more detailed descriptions are included 
in the Development Document for Proposed Effluent Limitations 
Guidelines and Standards for the Coastal Subcategory of the Oil and Gas 
Extraction Point Source Category, referred to hereafter as the 
``Coastal Technical Development Document''. Today's proposal presents 
EPA's selected technology approach and several others that were 
considered in the regulation development process. The proposed rule is 
based on a detailed evaluation of data acquired during the development 
of the proposed limitations. As indicated below in the discussion of 
the specifics of the proposal, EPA welcomes comment on all options and 
issues and encourages commenters to submit additional data during the 
comment period. Also, EPA is willing to meet with interested parties 
during the comment period to ensure that EPA has the views of all 
parties and the best possible data upon which to base a decision for 
the final regulation. EPA emphasizes that it is soliciting comments on 
all options suggested in and raised by this proposal and that it may 
adopt any such options or combination of options in the final rule.

B. Summary of Proposed Coastal Guidelines

    EPA proposes to establish regulations based on ``best practicable 
control technology currently available ''(BPT) for one specific 
wastestream for which BPT does not currently apply, and ``best 
conventional pollutant control technology'' (BCT), ``pretreatment 
standards for existing sources'' (PSES), ``best available technology 
economically achievable'' (BAT), best available demonstrated control 
technology (BADCT) for new sources, and ``pretreatment standards for 
new sources'' (PSNS) for the remaining waste streams.
    Under this rule, EPA is co-proposing three options for the control 
of drilling fluids and cuttings (including any effluent from dewatering 
pit closures activities) for BAT effluent limitations guidelines, and 
NSPS. The three options considered contain zero discharge for all 
areas, except two of the options contain allowable discharges for Cook 
Inlet. One of these options, which would allow discharges meeting a 
more stringent toxicity limitation if selected for the final rule, 
would require an additional notice for public comment since the 
specific toxicity limitation has not been determined at this time. The 
three options are: Option 1--zero discharge of all areas except Cook 
Inlet where discharge limitations require toxicity of no less than 
30,000 ppm (SPP), no discharge of free oil and diesel oil and no more 
than 1 mg/l mercury and 3 mg/l cadmium in the stock barite, Option 2--
zero discharge for all areas except for Cook Inlet were discharge 
limitations would be the same as Option 1, except toxicity would be set 
to meet a limitation between 100,000 ppm (SPP) and 1 million ppm (SPP), 
and Option 3--zero discharge for all areas. EPA is proposing PSES and 
PSNS prohibiting all discharges of drilling fluids and drill cuttings. 
BCT for drilling fluids and cuttings is being proposed as zero 
discharge for the entire subcategory except for Cook Inlet, Alaska. BCT 
limitations for drilling fluids and cuttings for Cook Inlet would 
require no discharge of free oil (as determined by the static sheen 
test).
    EPA is proposing to prohibit discharges of produced water from all 
coastal subcategory operations except those located in Cook Inlet, 
Alaska, [[Page 9430]] under BAT. Proposed BAT for coastal facilities in 
Cook Inlet would limit the discharge of oil and grease in produced 
water to a daily maximum of 42 mg/l and a thirty day average of 29 mg/
l. EPA is proposing to prohibit discharges of produced water from all 
coastal subcategory operations under NSPA, PSNS, and PSES. BCT limits 
for produced waters in all coastal regions (including Cook Inlet) would 
be set equal to the current BPT limitations, which limit the discharge 
of oil and grease to a daily maximum of 72 mg/l and a thirty day 
average of 48 mg/l.
    BCT for treatment, workover and completion fluids is proposed to be 
set equal to current BPT limits prohibiting discharges of free oil, 
with compliance to be determined by use of the static sheen test. EPA 
is co-proposing two options for BAT and NSPS limitations for treatment, 
workover and completion finds. Option 1 would require no discharge of 
free oil and prohibit discharges to freshwaters of Texas and Louisiana. 
This option reflects current practice. Option 2 would require the same 
limitations as the preferred option for produced water. This option 
would require for BAT that discharges of treatment, workover and 
completion fluids would be prohibited in all coastal areas except Cook 
Inlet. In Cook Inlet, these discharges would be required to meet a 
daily maximum oil and grease limitation of 42 mg/l and a 30 day average 
of 29 mg/l. Option 2 would require zero discharge of these fluids 
everywhere for NSPS. EPA proposes zero discharge as PSES, and PSNS for 
treatment, workover and completion fluids.
    BPT, BCT, BAT, NSPS, PSES and PSNS are being proposed for produced 
sand and would prohibit all discharges of this wastestream. The only 
BPT effluent limitations guidelines being proposed today are for 
produced sand which is the only wastestream for which BPT limits have 
not been previously promulgated.
    BCT, BAT, and NSPS limits being proposed for deck drainage would be 
set equal to current BPT limits prohibiting discharges of free oil, 
with compliance to be determined by use of the visual sheen test. EPA 
is proposing zero discharge for PSES and PSNS for deck drainage because 
collection and capture of this wastestream is technically impractical 
in many situations (as discussed later in Section VI.D.) such that its 
direction to POTW's would rarely if ever occur. EPA also believes that 
combining this wastestream with municipal treatment facilities that may 
already be at full capacity should not be encouraged.
    BCT is being proposed for domestic wastes as equal to BPT (which is 
no discharge of floating solids) with an additional requirement 
prohibiting the discharge of garbage. BAT is being proposed for 
domestic wastes to prohibit discharge of foam. NSPS is being proposed 
for domestic wastes as equal to BCT and no discharge of foam and no 
discharge of garbage. No pretreatment standards are being established 
for domestic wastes.
    BCT and NSPS limitations for sanitary wastes are being proposed as 
equal to the current BPT effluent limitations guidelines. Sanitary 
waste effluents from facilities continuously manned by ten (10) or more 
persons would contain a minimum residual chlorine content of 1 mg/1, 
with the chlorine level maintained as close to this concentration as 
possible. Coastal facilities continuously manned by nine or fewer 
persons or only intermittently manned by any number of persons must 
comply with a prohibition on the discharge of floating solids. BAT is 
not being developed for sanitary wastes because no toxic or 
nonconventional pollutants of concern have been identified in this 
waste stream. No pretreatment standards are being established for 
sanitary wastes.
    Compliance with these proposed limitations would result in a yearly 
decrease of 4.3 billion pounds of toxic, nonconventional and 
conventional pollutants in produced water, from zero to 23 million 
pounds of toxic nonconventional and conventional pollutants in drilling 
fluids and drill cuttings (depending on the option considered), and 
zero to 3.9 million pounds of toxic, nonconventional, and conventional 
pollutants in treatment, workover, and completion fluids (depending on 
the option considered).
    EPA expects a variety of human health, and environmental benefits 
to result from these reductions in effluent loadings. In particular, 
the benefits include: Relief to coastal waters which support spawning 
grounds, nurseries and habitats for commercial and recreational 
fisheries: Reducing documented aquatic ``dead zone'' impacts; reduction 
of potential cancer risks to anglers from consuming seafood 
contaminated by produced water radionuclides; and reducing potential 
exposure of endangered species to toxic contaminants. This proposal 
will result in total benefits ranging from $3.2 to $230 million (in 
1990 $'s) due to reduced cancer risks and increased recreational values 
of wetlands.
    Since the inception of the project in 1994, there have been 
periodic meetings with the industry and several trade associations, 
including the Louisiana and Texas Independent Oil and Gas Associations 
(TIOGA and LIOGA) and American Petroleum Institute (API) to discuss 
progress on the rulemaking. The Agency also has met with the Natural 
Resources Defense Council (NRDC) to discuss progress on this 
rulemaking. Because all of the facilities affected by this proposal are 
direct discharges, the Agency did not conduct an outreach survey of 
POTWs.
    The Agency also held a public meeting on July 19, 1994. The purpose 
of the meeting was to present the project status and discuss the 
technical options under consideration for this proposal. 
Representatives from industry trade associations, individual industry 
companies, state regulatory authorities, the U.S. Department of Energy 
and Interior (Minerals Management Service) and the Sierra Club Legal 
Defense Fund attended.
    The Agency will continue this process of consulting with state, 
local, and other affected parties after proposal in order to further 
minimize the potential for unfunded mandates that may result from this 
rule. These proposed requirements, when promulgated, will be 
implemented via the existing regulatory structure and no additional 
burden is expected.

C. The EPA Region VI Coastal Oil and Gas Production NPDES General 
Permits

    EPA's Region VI has recently published final NPDES General permits 
regulating produced water and produced sand discharges to coastal 
waters in Louisiana and Texas (60 FR 2387, Jan. 9, 1995). The permits 
prohibit the discharge of produced water and produced sand derived from 
the coastal subcategory to any water subject to EPA jurisdiction under 
the Clean Water Act.
    Much of the industry covered by today's proposed rulemaking is also 
covered by these General permits. However, a significant difference 
between the permits and this proposal is that the permits do not cover 
produced water discharges derived from the Offshore subcategory wells 
into the main deltaic passes of the Mississippi River, or to the 
Atchafalaya River below Morgan City including Wax Lake Outlet. The 
rulemaking being proposed today would cover these discharges (see the 
discussion below entitled ``C. Preventing the Circumvention of Effluent 
Limitations Guidelines and New Source Performance Standards'').
    Due to the close proximity of the timing of the publication of the 
Region 6 permits and this proposal, this preamble presents the costs 
and impacts of today's rulemaking as if the Region Vi 
[[Page 9431]] General permits were not final. As presented in later 
sections of this preamble, today's proposal (including the facilities 
covered by the Region VI permit) would remove 4.3 billion pounds of 
pollutants in produced water from being discharged per year. The Region 
VI permit covers approximately 71 percent of the produced water volume 
being discharged in the coastal subcategory. The remaining 29 percent 
is derived from coastal facilities treating offshore produced waters 
and currently discharging them into main deltaic river passes in 
Louisiana, as well as from other coastal operations in the U.S. Thus, 
with the Region VI General permits final, this rule would actually 
result in the removal of 1.25 billion pounds (29 percent of 4.3 billion 
pounds) of pollutants per year from being discharged into coastal 
waters.
    As also presented in later sections of this preamble, compliance 
costs of today's rulemaking (including the facilities covered by the 
Region VI permit) total approximately $40.4 million annually. With the 
Region VI General permits final, the costs of this rule would be 
reduced to approximately $19.9 million annually.
    EPA will more fully incorporate regulatory effects of the Region VI 
General permits upon promulgation of the final rule.

D. Preventing the Circumvention of Effluent Limitations Guidelines and 
New Source Performance Standards

    This rule also proposes a provision intended to prevent oil and gas 
facilities subject to Part 435 of this title from circumventing the 
effluent limitations guidelines, new source performance standards and 
pretreatment standards applicable to those facilities by moving 
effluent from one subcategory to another subcategory. When EPA 
establishes its effluent limitations guidelines and standards, it does 
so based on a determination, supported by analyses contained in the 
rulemaking record, that facilities in that subcategory, among other 
factors also considered under the CWA, can technologically and 
economically achieve the requirements of the rule. The purpose of the 
rule is not accomplished if facilities move effluent from a subcategory 
with more stringent requirements to a subcategory with less stringent 
requirements or if facilities move effluent from a subcategory with 
less stringent requirements to a subcategory with more stringent 
requirements and discharge effluent at the less stringent limitations. 
Until now, EPA has attempted to prevent this circumvention in the 
National Pollution Discharge Elimination System (NPDES) permits issued 
for this industry. EPA believes, however, that it would enhance the 
enforcement of these provisions to include them as part of the effluent 
limitations guidelines, new source performance standards and 
pretreatment standards.
    Therefore, this rule proposes to prohibit oil and gas facilities 
from moving effluent from a subcategory with more stringent 
requirements to a subcategory with less stringent requirements, unless 
that effluent is discharged in compliance with the limitations imposed 
by the more stringent subcategory. For example, facilities could not 
move produced water generated from the onshore subcategory of the oil 
and gas industry (which is subject to zero discharge requirements) to 
the offshore subcategory of the oil and gas industry and dispose of the 
effluent at the offshore limitations and standards. Similarly, this 
rule proposes to prohibit facilities from moving produced water 
generated from the offshore subcategory to the coastal or onshore 
subcategory and discharging the produced water at the offshore 
limitations. (An offshore oil and gas facility could, however, pipe 
produced water to shore for treatment and return it to offshore waters 
for disposal at the offshore limits. Disposal of such produced water 
onshore however, would be subject to zero discharge.) EPA intends that 
these provisions would be applied prospectively in future NPDES 
permits.

E. Common Sense Initiative

    On August 19, 1994, the Administrator established the Common Sense 
Initiative (CSI) Council in accordance with the Federal Advisory 
Committee Act (U.S.C. Appendix 2, Section 9 (c)) requirements. A 
principal goal of the CSI includes developing recommendations for 
optimal approaches to multimedia controls for industrial sectors 
including Petroleum Refining, Metal Plating and Finishing, Printing, 
Electronics and Computers, Auto Manufacturing, and Iron and Steel 
Manufacturing. The following are the six overall objectives of the CSI 
program, as stated in the ``Advisory Committee Charter.''
     Regulation. Review existing regulations for opportunities 
to get better environmental results at less cost. Improve new rules 
through increased coordination.
     Pollution Prevention. Actively promote pollution 
prevention as the standard business practice and a central ethic of 
environmental protection.
     Recordkeeping and Reporting. Make it easier to provide, 
use, and publicly disseminate relevant pollution and environmental 
information.
     Compliance and Enforcement. Find innovative ways to assist 
companies that seek to comply and exceed legal requirements while 
consistently enforcing the law for those that do not achieve 
compliance.
     Permitting. Improve permitting so that it works more 
efficiently, encourages innovation, and creates more opportunities for 
public participation.
     Environmental Technology. Give industry the incentives and 
flexibility to develop innovative technologies that meet and exceed 
environmental standards while cutting costs.
    The coastal oil and gas extraction rulemaking effort was not among 
those included in the Common Sense Initiative. However, many oil and 
gas producers (mostly large companies) involved in coastal oil and gas 
extraction activities also have refineries. These companies are 
projected to incur costs associated with the requirements contained in 
this proposal, however, these costs are not projected to have an 
economic impact at the firm level. The Agency believes that the CSI 
objectives already have been incorporated into the coastal oil and gas 
extraction industry rulemaking, and the Agency intends to continue to 
pursue these objectives. The Agency particularly will focus on avenues 
for giving state and local authorities flexibility in implementing this 
rule, and giving the industry flexibility to develop innovative and 
costs effective compliance strategies. In developing this rule, EPA 
took advantage of several opportunities to gain the involvement of 
various stakeholders. Sections III. E, V and X of this preamble 
describe consultations with state and local governments and other 
parties including the industry. EPA has internally coordinated among 
relevant program offices in developing this rule as well. Section XIV 
describes related rulemakings that are being developed by EPA's Office 
of Air Quality, Planning and Standards, Underground Injection Control 
Program, and Spill Prevention, Control and Countermeasure Program. EPA 
will be monitoring these related rulemakings to assess their collective 
costs to the industry. Section VIII of the preamble describes the non-
water quality impacts this proposed rule would have on other media 
including air emissions and solid waste disposal. [[Page 9432]] 

III. Background

A. Clean Water Act

1. Statutory Requirements of Regulations
    The objective of the Clean Water Act (CWA) is to ``restore and 
maintain the chemical, physical, and biological integrity of the 
Nation's waters''. CWA Sec. 101(a). To assist in achieving this 
objective, EPA issues effluent limitation guidelines, pretreatment 
standards, and new source performance standards for industrial 
dischargers. These guidelines and standards are summarized below:
a. Best Practicable Control Technology Currently Available (BPT)--Sec. 
304(b)(1) of the CWA
    BPT effluent limitations guidelines apply to discharges of 
conventional, priority, and non-conventional pollutants from existing 
sources. BPT guidelines are generally based on the average of the best 
existing performance by plants in a category or subcategory. In 
establishing BPT, EPA considers the cost of achieving effluent 
reductions in relation to the effluent reduction benefits, the age of 
equipment and facilities, the processes employed, process changes 
required, engineering aspects of the control technologies, non-water 
quality environmental impacts (including energy requirements), and 
other factors as the EPA Administrator deems appropriate. CWA 
Sec. 304(b)(1)(B). Where existing performance is uniformly inadequate, 
BPT may be transferred from a different subcategory or category.
b. Best Conventional Pollutant Control Technology (BCT)--Sec. 304(b)(4) 
of the CWA
    The 1977 amendments to the CWA established BCT as an additional 
level of control for discharges of conventional pollutants from 
existing industrial point sources. In addition to other factors 
specified in section 304(b)(4)(B), the CWA requires that BCT 
limitations be established in light of a two part ``cost-
reasonableness'' test. EPA published a methodology for the development 
of BCT limitations which became effective August 22, 1986 (51 FR 24974, 
July 9, 1986).
    Section 304(a)(4) designates the following as conventional 
pollutants: biochemical oxygen demanding pollutants (measured as 
BOD5), total suspended solids (TSS), fecal coliform, pH, and any 
additional pollutants defined by the Administrator as conventional. The 
Administrator designated oil and grease as an additional conventional 
pollutant on July 30, 1979 (44 FR 44501).
c. Best Available Technology Economically Achievable (BAT)--Sec. 
304(b)(2) of the CWA
    In general, BAT effluent limitations guidelines represent the best 
existing economically achievable performance of plants in the 
industrial subcategory or category. The CWA establishes BAT as a 
principal national means of controlling the direct discharge of toxic 
and nonconventional pollutants. The factors considered in assessing BAT 
include the age of equipment and facilities involved, the process 
employed, potential process changes, non-water quality environmental 
impacts, including energy requirements, and such factors as the 
Administrator deems appropriate. The Agency retains considerable 
discretion in assigning the weight to be accorded these factors. An 
additional statutory factor considered in setting BAT is economic 
achievability across the subcategory. Generally, the achievability is 
determined on the basis of total costs to the industrial subcategory 
and their effect on the overall industry financial health. As with BPT, 
where existing performance is uniformly inadequate, BAT may be 
transferred from a different subcategory or category. BAT may be based 
upon process changes or internal controls, even when these technologies 
are not common industry practice.
d. Best Available Demonstrated Control Technology For New Sources 
(BADCT)--Section 306 of the CWA
    NSPS are based on the best available demonstrated treatment 
technology and apply to all pollutants (conventional, nonconventional, 
and toxic). New plants have the opportunity to install the best and 
most efficient production processes and wastewater treatment 
technologies. Under NSPS, EPA is to consider the best demonstrated 
process changes, in-plant controls, and end-of-process control and 
treatment technologies that reduce pollution to the maximum extent 
feasible. In establishing NSPS, EPA is directed to take into 
consideration the cost of achieving the effluent reduction and any non-
water quality environmental impacts and energy requirements.
e. Pretreatment Standards for Existing Sources (PSES)--Sec. 307(b) of 
the CWA
    PSES are designed to prevent the discharge of pollutants that pass 
through, interfere with, or are otherwise incompatible with the 
operation of publicly-owned treatment works (POTW). The CWA authorizes 
EPA to establish pretreatment standards for pollutants that pass 
through POTWs or interfere with treatment processes or sludge disposal 
methods at POTWs. Pretreatment standards are technology-based and 
analogous to BAT effluent limitations guidelines.
    The General Pretreatment Regulations, which set forth the framework 
for the implementation of categorical pretreatment standards, are found 
at 40 CFR Part 403. Those regulations contain a definition of pass-
through that addresses localized rather than national instances of 
pass-through and establish pretreatment standards that apply to all 
non-domestic dischargers. See 52 FR 1586, January 14, 1987.
f. Pretreatment Standards for New Sources (PSNS)--Sec. 307(b) of the 
CWA
    Like PSES, PSNS are designed to prevent the discharges of 
pollutants that pass through, interfere with, or are otherwise 
incompatible with the operation of POTWs. PSNS are to be issued at the 
same time as NSPS. New indirect dischargers have the opportunity to 
incorporate into their plants the best available demonstrated 
technologies. The Agency considers the same factors in promulgating 
PSNS as it considers in promulgating NSPS.
g. Best Management Practices (BMPs)
    Section 304(e) of the CWA gives the Administrator the authority to 
publish regulations, in addition to the effluent limitations guidelines 
and standards listed above, to control plant site runoff, spillage or 
leaks, sludge or waste disposal, and drainage from raw material storage 
which the Administrator determines may contribute significant amounts 
of pollutants.
h. CWA Section 304(m) Requirements
    Section 304(m) of the CWA requires EPA to establish schedules for 
(i) reviewing and revising existing effluent limitations guidelines and 
standards and (ii) promulgating new effluent guidelines. On January 2, 
1990, EPA published an Effluent Guidelines Plan (55 FR 80), in which 
schedules were established for developing new and revised guidelines 
for several industry categories, including the coastal oil and gas 
industry. Natural Resources Defense Council, Inc., challenged the 
Effluent Guidelines Plan in a suit filed in the U.S. District Court for 
the District of Columbia, (NRDC et al v. Reilly, Civ. No. 89-2980). On 
January 31, 1992, the Court entered a consent decree (the ``304(m) 
Decree''), which establishes [[Page 9433]] schedules for, among other 
things, EPA's proposal and promulgation of effluent guidelines for a 
number of point source categories, including the Coastal Oil and Gas 
Industry. The most recent Effluent Guidelines Plan was published in the 
Federal Register on August 26, 1994 (59 FR 44234). This plan requires, 
among other things, that EPA propose the Coastal Guidelines by January 
1995 and promulgate the Guidelines by July 1996.
2. Prior Federal Rulemakings and Other Notices
    Coastal subcategory effluent limitations were proposed on October 
13, 1976 (41 FR 44943). On April 13, 1979 (44 FR 22069) BPT effluent 
limitations guidelines were promulgated for all subcategories under the 
oil and gas category, but action on the BAT and NSPS regulations was 
deferred. Table 1 presents the 1979 BPT limitations.

                            Table 1.--Coastal Subcategory BPT Effluent Limitations\2\                           
----------------------------------------------------------------------------------------------------------------
               Waste stream                             Parameter                   BPT effluent limitation     
----------------------------------------------------------------------------------------------------------------
Produced Water............................  Oil and Grease...................  72 mg/l Daily Maximum            
                                                                               48 mg/l 30-Day Average.          
Drilling Cuttings.........................  Free Oil\1\......................  No Discharge.                    
Drilling Fluids...........................  Free Oil\1\......................  No Discharge.                    
Well Treatment Fluids.....................  Free Oil\1\......................  No Discharge.                    
Deck Drainage.............................  Free Oil\1\......................  No Discharge.                    
Sanitary-M10..............................  Residual Chlorine................  1 mg/l (minimum).                
Sanitary-M91M.............................  Floating Solids..................  No Discharge.                    
Domestic Wastes...........................  Floating Solids..................  No Discharge.                    
----------------------------------------------------------------------------------------------------------------
\1\The free oil ``no discharge'' limitation is implemented by requiring no oil sheen to be present upon         
  discharge (visual sheen).                                                                                     
\2\40 CFR Part 435, Subpart D.                                                                                  

    On November 8, 1989, EPA published a notice of information and 
request for comments on the Coastal Oil and Gas subcategory effluent 
limitations guidelines development (54 FR 46919). The notice presented 
information known to date about control and treatment technologies, 
applicable to oil and gas wastes as well as the Agency's anticipated 
approach to effluent limitations guidelines development for BAT, BCT, 
and NSPS. It also solicited comments on the information presented as 
well as the limitations development approach and requested additional 
information where available.

B. Pollution Prevention Act
    In the Pollution Prevention Act of 1990 (PPA) (42 U.S.C. 13101 et 
seq., Pub. L. 101-508, November 5, 1990), Congress declared pollution 
prevention the national policy of the United States. The PPA declares 
that pollution should be prevented or reduced whenever feasible; 
pollution that cannot be prevented or reduced should be recycled or 
reused in an environmentally safe manner wherever feasible; pollution 
that cannot be recycled should be treated in an environmentally safe 
manner wherever feasible; and disposal or release into the environment 
should be chosen only as a last resort.
    Today's proposed rules are consistent with this policy. In fact, 
for the two major wastestreams generated by this industry, EPA is 
proposing zero discharge for drilling fluids and cuttings, as well as 
zero discharge for approximately 80 percent of the volume of produced 
water. Zero discharge of wastes is an alternative that prevents 
pollution to the maximum extent possible. As described later in this 
notice, development of these proposed rules focused on pollution-
preventing technologies, such as drilling fluids closed-loop recycle 
systems and produced water injection systems, that some segments of the 
industry have already adopted.

C. Coastal Subcategory Definition

    The coastal oil and gas regulations at 40 CFR 435.41(e) currently 
define the coastal subcategory as follows:
    ``(1) any body of water landward of the territorial seas as defined 
in 40 CFR 125.1(gg) or (2) any wetlands adjacent to such waters.'' Part 
125 was revised at 44 FR 32948 (June 7, 1979).
    EPA proposes to clarify the ``coastal'' definition in this rule. 
First, EPA intends to revise the regulation to state that the coastal 
subcategory would consist of ``any oil and gas facility located in or 
on a water of the United States landward of the territorial seas.'' As 
suggested by the preamble to the 1979 guidelines in discussing the 
coastal definition (44 FR 22017; April 13, 1979), EPA intended the 
subcategory to cover all facilities located over waters under CWA 
jurisdiction, including adjacent wetlands. Courts have made it clear 
that isolated wetlands with an interstate commerce connection, as well 
as adjacent wetlands, are waters of the United States subject to CWA 
jurisdiction. See, e.g., Hoffman Homes, Inc. v. Administrator 999 F.2d 
256 (7th Cir. 1993). The revised definition would make it clear that 
facilities located in or on isolated wetlands would be considered to be 
coastal. This application of the coastal definition is consistent with 
the EPA Region 6 final general permit for coastal drilling operations. 
58 FR 49126 (September 21, 1993).
    In addition, the revised definition would no longer refer to 40 CFR 
125.1(gg). Part 125 was revised at 44 FR 32948 (June 7, 1979) and no 
longer exists in the CFR. That provision, when it did exist, merely 
cited section 502(8) of the CWA which defines territorial seas as ``the 
belt of seas measured from the line of ordinary low water along that 
portion of the coast which is in direct contact with the open sea and 
the line marking the seaward limit of inland waters, and extending 
seaward a distance of three miles.'' 40 CFR 125.1(gg) (July 1, 1978). 
That statutory definition is still in effect.
    Also, EPA would explicitly include in the definition of ``coastal'' 
certain wells located in the area between the Chapman line and the 
inner boundary of the territorial seas that were determined to be 
coastal as a result of a decision of the U.S. Court of Appeals for the 
Fifth Circuit. American Petroleum Institute v. EPA, 661 F.2d 340 (5th 
Cir. 1981). The Chapman line is formed by a series of 40 latitude and 
longitude coordinates that roughly parallel the Louisiana and Texas 
coastline to the Mexican border. EPA's interim final regulations issued 
in 1976 (41 FR 44942; October 13, 1976) defined ``coastal'' to include 
all land and water areas landward of the inner boundary of the 
territorial seas and eastward of the point defined by 89 degrees 45 
minutes West Longitude and 29 degrees 46 [[Page 9434]] minutes North 
latitude and continuing west of that point through the series of 
longitude and latitude coordinates (the Chapman Line) to the point 97 
degrees 19 minutes West Longitude and continuing southward to the U.S.-
Mexican border.) So defined, the coastal area included areas on the 
Gulf coast of Texas and Louisiana. The 1976 boundaries were set to 
include wells located in both water and on land within the geographic 
area defined as coastal.
    On April 13, 1979 (44 FR 22069), EPA redefined the coastal 
subcategory as set forth at 40 CFR 435.41(e). This new definition 
eliminated reference to the Chapman line, and instead, defined coastal 
with respect to a well's location over water bodies or wetlands. Under 
this definition, certain wells located on land, but discharging to 
coastal areas, were reclassified into the onshore subcategory and 
others were reclassified as stripper wells, depending on their 
production rate. The wells that were classified as onshore were 
required to meet zero discharge which is the standard applicable to 
onshore facilities. Industry challenged EPA's 1979 final rule. In 
American Petroleum Institute v. EPA, 661 F.2d 340, 354-57 (5th Cir., 
1981), the Court held that EPA had failed to consider adequately the 
cost to the reclassified facilities of this regulatory change. As a 
result of the Court's decision, EPA suspended the applicability of the 
onshore subcategory guidelines (40 CFR 435.30) to the reclassified 
wells and to any wells that came into existence in the affected area 
after the issuance of the 1979 redefinition. See 47 FR 31554 (July 21, 
1982). Thus, the wells affected by this suspension are classified as 
coastal. To reflect this fact, the definition of coastal in 40 CFR 
453.41(e) would be revised to include facilities subject to the 
suspension.

D. New Source Definition

    The definition of ``new source'' as it applies to the Offshore 
Guidelines was discussed at length in EPA's 1985 proposal, (50 FR 
34617-34619, August 26, 1985) and in EPA's final rule (58 FR 12456-
12458, March 4, 1993). EPA proposes that this definition would also 
apply to the coastal oil and gas industry. As discussed in the 1985 
proposal and 1993 final rule, provisions in the NPDES regulations 
define new source (40 CFR 122.2) and establish criteria for a new 
source determination (40 CFR 122.29(b)). EPA is proposing special 
definitions which are consistent with 40 CFR 122.29 and which provide 
that 40 CFR 122.2 and 122.29(b) shall apply ``except as otherwise 
provided in an applicable new source performance standard.'' (See 49 FR 
38046, Sept. 26, 1984.)
    In summary, for coastal operations a drilling operation would be a 
new source if the drilling rig is drilling a coastal development well 
(not an exploratory well) in a new water area. Exploratory or 
development well drilling from an existing platform or rig that has not 
moved since it drilled a previously existing well would not be a new 
source. For production, a new source would be a facility discharging 
from a new site.
    EPA invites comments on the definition of new sources as it applies 
to the coastal oil and gas subcategory.
E. Summary of Public Participation

    EPA encourages full public participation in developing the final 
Coastal Guidelines. During the data gathering activities that preceded 
development of the proposed rule, EPA received written comments on the 
1989 Notice of Information and Request for Comments and has met with 
representatives from industry and environmental groups, as well as 
state and other federal agencies. To further public participation on 
this rule, on July 19, 1994, EPA held a public meeting about the 
content and the status of the proposed regulation. The meeting was 
announced in the Federal Register (59 FR 31186; June 17, 1994), and 
information packages were distributed at the meeting. The public 
meeting also gave interested parties an opportunity to provide 
information, data, and ideas to EPA on key issues. EPA will assess all 
comments and data received at that public meeting along with comments 
and data received as a result of this proposal as well as the 1989 
Notice of Information, prior to promulgation.
    During the development of the proposed Coastal Guidelines, EPA sent 
a questionnaire to industry under authority of section 308 of the CWA. 
During its design, EPA met with industry trade associations (on March 
19, 1992) to discuss its plans to issue a questionnaire. Following the 
March meeting, EPA distributed a draft of the questionnaire to NRDC, 
industry representatives, and trade associations for review and 
comment. On May 7, 1992, EPA met with industry representatives to 
discuss industry comments. NRDC did not provide comments. A final 
questionnaire was subsequently completed, reviewed and approved by the 
Office of Management and Budget (OMB) and sent to coastal oil and gas 
operators on August 30, 1993.

IV. Description of the Industry

A. Industry Description

    Drilling in coastal areas occurs onland as well as over water or 
wetlands. Drilling occurs in two phases: Exploration and development. 
Exploration activities are those operations involving the drilling of 
wells to locate hydrocarbon bearing formations and to determine the 
size, and production potential of hydrocarbon reserves. Development 
activities involve the drilling of production wells once a hydrocarbon 
reserve has been discovered and delineated.
    Drilling for oil and gas is generally performed by rotary drilling 
methods which involve the use of a circularly rotating drill bit that 
grinds through the earth's crust as it descends. Drilling fluids are 
injected down through the drill bit via a pipe that is connected to the 
bit, and serve to cool and lubricate the bit during drilling. The rock 
chips that are generated as the bit drills through the earth are termed 
drill cuttings. The drilling fluid also serves to transport the drill 
cuttings back up to the surface through the space between the drill 
pipe and the well wall (this space is termed the annulus), in addition 
to controlling downhole pressure.
    As drilling progresses, large pipes called ``casing'' are inserted 
into the well to line the well wall. Drilling continues until the 
hydrocarbon bearing formations are encountered. In coastal areas, wells 
depths range from approximately 8,000-12,000 feet deep, and it takes 
approximately 20-60 days to complete drilling.
    On the surface, the drilling fluid and drill cuttings undergo an 
extensive separation process to remove as much solids (e.g., cuttings) 
from the fluid as possible. The fluid is then recycled into the system, 
and the cuttings become a waste product. Intermittently during 
drilling, and at the end of the drilling process, drilling fluids may 
become wastes if they can no longer be reused or recycled.
    Once the target formations have been reached, and a determination 
made as to which have commercial potential, the well is made ready for 
production by a process termed ``completion''. Completion involves 
cleaning the well to remove drilling fluids and debris, the perforation 
of the casing that lines the producing formation, insertion of 
production tubing to transport the hydrocarbon fluids to the surface, 
and installation of the surface wellhead. The well is now ready for 
production, or actual extraction of hydrocarbons. [[Page 9435]] 
    The hydrocarbons extracted from the well usually consist of a 
combination of oil, gas, and brines (produced water). These fluids are 
initially directed from the wellhead to a separation facility where gas 
and oil are separated out and either treated further or sent directly 
offsite for sales, and the produced waters undergo further separation 
to remove as much oil as possible from the water.
    The separation facilities, or production facilities, consist of the 
treatment equipment and storage tanks that process the produced fluids. 
Production facilities may be configured to service one well, or as 
central facilities which service multiple satellite wells, also known 
as tank batteries or gathering centers.
    Coastal production facilities can be located over water or on land. 
Production facilities located over water exist in generally two types 
of configurations: (1) Individual deep water multi-well platforms or; 
(2) central facilities supported on barges or wooden or concrete 
pilings that service multiple satellite wells in shallow water. 
Production facilities on land may service satellite wells in any 
combination of locations. The type of configuration is an important 
factor when examining costs of installing pollution control equipment.
    Multi-well platforms, such as those found in the Gulf of Mexico 
offshore region, are not commonly found in the coastal region of the 
Gulf of Mexico. Based on an earlier mapping effort of all oil and gas 
wells, EPA determined that there are only four structures owned and 
operated by four different operators in the coastal Gulf of Mexico 
region that can be classified as multi-well platforms. However in the 
Gulf coastal areas, many single wellheads are located throughout the 
coastal waters, serviced by gathering centers located on-land or on 
platforms. Although there are some exceptions, in most cases those 
located on land can be accessed by car or truck (land-access) while 
those facilities located over water must be accessed by boat or barge 
(water-access). An analysis of the EPA 1993 Coastal Oil and Gas 
Questionnaire data results indicates that approximately 34 percent of 
the production facilities in the Gulf of Mexico are land accessed, and 
66 percent are water-accessed facilities. (See Section V.B for 
description of the Questionnaire). This distinction is important when 
estimating regulatory compliance costs and impacts as described in 
sections VI and VIII. On the other hand, all coastal structures in Cook 
Inlet, Alaska are deep water multi-well platforms, all accessible only 
by water (or air) transportation.
    Depending on operational preference or regulatory requirements, 
many of the coastal production facilities do not discharge produced 
water and thus, would not incur costs due to this rulemaking.
B. Location

    Coastal oil and gas activities are located on water bodies inland 
of the inner boundary of the territorial seas. These water bodies 
include inland lakes, bays and sounds, as well as saline, brackish, and 
freshwater wetland areas. Although the definition includes water bodies 
even in all inland U.S. states, EPA knows of no existing operations 
other than those in certain states bordering the coast. Thus, at this 
time, the coastal oil and gas operations are located only in coastal 
states.
    Current coastal oil and gas activity exists along the Gulf of 
Mexico coastal states of Texas, Louisiana, Alabama and Florida, in San 
Pedro Bay, California and also in Alaska's Cook Inlet and the North 
Slope areas. The majority of Gulf Coast activity takes place in Texas 
and Louisiana. There, coastal oil and gas operations exist in a number 
of topographical situations including bays, sounds, lakes, and 
wetlands. Coastal oil and gas activity in Alabama is located in Mobile 
Bay; and a small number of wells are also located in wetlands along the 
west coast of Florida.
    Coastal oil and gas activity in California exists behind the 
barrier island that forms San Pedro Bay (in Long Beach Harbor). There, 
four man-made islands have been constructed solely for the purpose of 
oil and gas extraction.
    Roughly one third of all the coastal oil and gas production 
activity exists in Alaska. Deep water platforms exist in the northern 
part of Cook Inlet. In addition, operations resembling onshore 
activities (as opposed to deep water platforms) are located on the 
tundra wetlands of Alaska's North Slope.

C. Activity

    Table 2 summarizes the number of producing wells and annual 
drilling activities for the coastal subcategory and the number of 
producing facilities that would incur costs (those still discharging 
after the projected final date of July 1996) due to this rulemaking, by 
geographic locations.

                                Table 2.--Profile of Coastal Oil and Gas Industry                               
----------------------------------------------------------------------------------------------------------------
                                                                                 Number of             Number of
                                                                                production             operators
                                                         Number of   Number of  facilities                that  
                                                         producing  production  that would    Annual     would  
  Coastal location                  Region                 wells    facilities     incur     drilling    incur  
                                                           (1992)     (1992)       costs     activity    costs  
                                                                                under this               under  
                                                                                   rule                this rule
----------------------------------------------------------------------------------------------------------------
Gulf of Mexico......  TX & LA..........................       4675         853         216        686        122
                      AL, FL...........................         56       ND\1\           0          7          0
Alaska..............  Cook Inlet.......................        237           8           8          8          5
                      North Slope......................       2085          12           0        161          0
California..........  Long Beach Harbor................        586           4           0          7          0
      Total.........    ...............................       7639         877         224        869       127 
----------------------------------------------------------------------------------------------------------------
\1\Not determined.                                                                                              

    Eight hundred and seventy seven (877) production facilities listed 
in Table 1 are currently discharging produced water in the coastal 
areas of Texas (TX), saline and brackish coastal waters of Louisiana 
(LA), and the Cook Inlet of Alaska. All coastal production facilities 
in Mississippi (MS), Alabama (AL), Florida (FL), the North Slope, and 
California do not discharge treated produced water, but rather inject 
it either for disposal or for waterflooding. [[Page 9436]] There are no 
discharges of drilling fluids and cuttings from coastal operators 
except for those in Cook Inlet. The volumes and locations of discharges 
are discussed in more detail in Section VI. By July 1996, the scheduled 
date for promulgation of this rule, EPA estimates that there will be 
216 facilities operated by 122 operators discharging produced water. 
This is based on data obtained directly from industry, the 1993 Coastal 
Oil and Gas Questionnaire, and state permit records.

D. Waste Streams

    The primary wastewater sources from the exploration and development 
phases of the coastal oil and gas extraction industry include the 
following:
     Drilling fluids.
     Drill cuttings.
     Sanitary wastes.
     Deck drainage.
     Domestic wastes.
    The primary wastewater sources from the production phase of the 
industry include the following:
     Produced water.
     Produced sand.
     Well treatment, workover, and completion fluids.
     Deck drainage.
     Domestic wastes.
     Sanitary wastes.
    Drilling fluids and drill cuttings are the most significant waste 
streams from exploratory and development operations in terms of volume 
and pollutants. Produced water is the largest waste stream from 
production activities in terms of volumes of discharged and quantity of 
pollutants. Deck drainage, sanitary wastes, domestic wastes, produced 
sand, and well treatment, completion, and workover fluids are often 
classified under the term miscellaneous wastes.
    A summary of the sources and characteristics of each of these 
wastes is presented in Section VI of this notice. Detailed discussions 
of the origins and characteristics of the waste water effluents from 
exploration, development, and production are included in the Coastal 
Technical Development Document. EPA has primarily focused data 
gathering efforts and data analyses on drilling fluids, drill cuttings, 
and produced water due to their volumes and potential toxicity. 
Information on the other waste streams discussed above is more limited. 
Their volumes are generally smaller, and in most cases are either 
infrequently discharged or are commingled with the major waste streams. 
However, EPA has determined that it is appropriate to propose 
regulations for these wastes as well.

E. Current NPDES Permits

    Discharges from coastal oil and gas operations in the Gulf of 
Mexico, California, and Alaska are regulated by general and individual 
NPDES permits based on BPT, State Water Quality Standards, and on Best 
Professional Judgment (BPJ) of BCT and BAT levels of control. Table 3 
lists the requirements in these permits.
    EPA's Region VI has developed general NPDES permits for each phase 
of oil and gas operations (drilling and production). The drilling 
permits for Louisiana and Texas were proposed in 1990 and a final 
permits published on September 21, 1993 (58 FR 49126). Region VI 
proposed general production permits on December 22, 1992 (57 FR 60926), 
and final permits on January 9, 1995 (60 FR 2387).
    EPA's Region X issued a BPT and BPJ general NPDES permit for oil 
and gas operations in the Upper Cook Inlet. However, although expired, 
conditions of this general permit are still fully effective and 
enforceable until the permit is reissued. Region X is currently in the 
process of reissuing the BPT and BPJ/BAT general permit for this area 
with proposal expected in early 1995. In addition to the general 
permit, the Region issued an individual permit regulating discharges 
from exploratory drilling operations in Upper Cook Inlet in May 1993. 
The individual permit was also based on BPT and BPJ/BAT.
    The State of Alabama, which has been authorized to administer the 
NPDES program, has also issued a final NPDES general permit covering 
facilities in state waters, including offshore and coastal facilities 
(including Mobile Bay). (Permit #ALG280000, May 25, 1994). This permit 
specifically prohibits the discharge of drilling fluids and cuttings, 
and produced water. The permit also does not allow the discharge of 
produced sands or treatment, workover and completion fluids.
    Regional permit requirements are based on other factors, in 
addition to technology pollutant removal performance, including water 
quality criteria.

                                                         Table 3.--NPDES Permit Requirements\1\                                                         
                                                             [Regional Permit Requirements]                                                             
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                     Region VI                          
                                                            Region X exploration permit      Region VI final        production        Region IV permit  
       Wastestream          Region X (Cl 1986 BPT permit)              (1993)                drilling permit      permit (final)           (1994)       
                                                                                                  (1993)              (1995)                            
--------------------------------------------------------------------------------------------------------------------------------------------------------
Produced Water...........  Monitor daily flow rate Oil &   Not applicable...............  Covered in Production  No Discharge....  No Discharge.        
                            Grease: Phillips A Platform                                    Permit.                                                      
                            20 mg/l daily max 15 mg/l mo.                                                                                               
                            ave. Other facilities: 48/72                                                                                                
                            mg/l pH=6-9.                                                                                                                
Produced Sand............  No free oil (Static Sheen)....  Not applicable...............  Not applicable.......  No Discharge....  No Discharge.        
Drilling Fluids and        (1) Toxicity: Discharge only    (1) Flowrate = 750 bbl/hr....  No Discharge.........  Not applicable..  No Discharge.        
 Cuttings.                  approved generic muds.                                                                                                      
                           (2) No free oil- static sheen.  (2) Use authorized muds only.                                                                
                           (3) No discharge oil-based      (3) Toxicity: 30,000 ppm in                                                                  
                            muds.                           SPP.                                                                                        
                           (4) 10 percent oil content for  (4) No free oil..............                                                                
                            cuttings.                                                                                                                   
                           (5) No diesel oil.............  (5) No discharge of oil-based                                                                
                                                            fluids.                                                                                     
                           (6) 1/3 mg/kg Hg/Cd in dry      (6) 5 percent (wt) oil                                                                       
                            barite.                         content in cuttings.                                                                        
                           (7) Flow rate.................  (7) No discharge of diesel                                                                   
                                                            oil.                                                                                        
                             >40m = 1000 bbl/hr..........  (8) 1 mg/kg Hg and 3 mg/kg Cd                                                                
                                                            in stock barite.                                                                            
[[Page 9437]]
                                                                                                                                                        
                             >20-40m = 750 bbl/hr........                                                                                               
                             >5-20m = 500 bbl/hr.........                                                                                               
                             <5m = No discharge..........                                                                                               
``Dewatering Effluent''..  Not separately regulated......  Not separately regulated       No free oil..........  Not applicable..  Not separately       
                                                                                                                                    regulated.          
                                                                                          50 mg/l TSS..........                                         
                                                                                          125 mg/l COD pH = 6-9                                         
                                                                                          500 mg/l chlorides...                                         
                                                                                          0.5 mg/l total Cr....                                         
                                                                                          5.0 mg/l Zn Monitor                                           
                                                                                           volume.                                                      
Treatment, Completion,     No free oil (Static Sheen)....  No discharge of free oil or    Freshwater: No         Not applicable..  No Discharge.        
 Workover Fluids.          No oil-based fluids...........   oil-based fluids.              discharge.                                                   
                           pH = 6-9......................  Monitor frequency of           Saline water: No                                              
                           Oil and grease limits apply to   discharge and volume pH =      toxics, No free oil                                          
                            combined discharge of any TWC   6.5-8.5.                       (visual sheen), pH =                                         
                            commingled with produced       Oil & grease = 72 daily max.    6-9                                                          
                            water.                          & 48 mo. avg.                                                                               
Domestic Wastes..........  No free oil (No visible sheen)  Monitor flow rate............  No discharge of        Not applicable..  Flow = 10,000 gpd    
                                                                                           solids (``garbage'').                    max.                
                           No Floating solids............  No free oil (No visible                                                 BOD5 = 45 mg/l daily 
                                                            sheen).                                                                 max.                
                           Monitor flow rate.............  No floating solids...........                                             = 30 mg/l          
                                                           No visible foam..............                                             (mo. aver.)        
                                                                                                                                   TSS = 45 mg/l daily  
                                                                                                                                    max.                
                                                                                                                                     = 30 mg/l          
                                                                                                                                      (mo. aver.)       
                                                                                                                                   Total residual       
                                                                                                                                    chlorine = 1.0 mg/l 
                                                                                                                                    (daily min)         
                                                                                                                                    maintained as close 
                                                                                                                                    to this value as    
                                                                                                                                    possible.           
                                                                                                                                   No Floating Solids.  
Deck Drainage............  No free oil (Visual Sheen)      Monitor flow rate (mo. avg.)   No free oil (visual    Not applicable..  Monitor daily flow   
                            Monitor flow rate (mo. ave.).   No free oil (visual sheen).    sheen) Monitor                          No free oil (visual  
                                                                                           volume.                                  sheen)              
Sanitary Wastes..........  No floating solids............  No free oil (No visible        No floating solids...  Not applicable..  Flow = 10,000 gpd    
                                                            sheen).                                                                 max.                
                           As close as possible to, but    No floating solids...........  BOD = 45 mg/l........                    BOD5 = 45 mg/l daily 
                            no less than 1.0 mg/l.                                                                                  max.                
                           BOD & SS2.....................  No visible foam..............  TSS = 45 mg/l fecal                        = 30 mg/l (mo.     
                                                                                           coliforms = 200/100                      aver.)              
                                                                                           mls Monitor flow.                       TSS = 45 mg/l daily  
                                                                                                                                    max.                
                                                                                                                                     = 30 mg/l (mo.     
                                                                                                                                    aver.)              
                                                                                                                                   Total residual       
                                                                                                                                    chlorine = 1.0 mg/l 
                                                                                                                                    (daily min)         
                                                                                                                                    maintained as close 
                                                                                                                                    to this value as    
                                                                                                                                    possible.           
                                                                                                                                   No Floating Solids.  
                             24 hr = 60 mg/l.............  As close as possible but no                                                                  
                                                            less than 1 mg/l.                                                                           
                             7 day = 45 mg/l.............  BOD: 30 day=30 mg/l..........                                                                
[[Page 9438]]
                                                                                                                                                        
                             30 day = 30 mg/l............   24 hr = 60 mg/l.............                                                                
                                                           TSS: 30 day = TSS intake + 30                                                                
                                                            mg/l.                                                                                       
                                                             24 hr = TSS intake + 60 mg/                                                                
                                                            l.                                                                                          
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1For a complete presentation of the effluent limitations and their bases in the permits see the following: Region X Proposed General Permit for Cook    
  Inlet: 50 FR 28974, 7/17/85, Region X Final Permit for Cook Inlet: 51 FR 35460, 10/3/86, Region VI Final General Permit for Drilling Operations: 58 FR
  49126, 9/21/93, Region VI Proposed General Permit for Production Operations: 57 FR 60926, 12/22/92. The Region X Exploration Permit and the Region IV 
  Permit are in the record for this rulemaking.                                                                                                         
2Limits apply only to discharges to state waters and separately for BOD and SS.                                                                         

V. Summary of Data Gathering Efforts

    The major studies presenting information on coastal oil and gas 
effluents and treatment technologies which have bearing on this 
proposed rule are summarized in this section. These investigations 
include: underground injection of produced water and associated 
produced water treatment technologies; solids control technologies for 
drilling fluids; drilling fluids and drill cuttings waste generation, 
treatment, and disposal in coastal Alaska; and commercial non-hazardous 
oil and gas waste disposal facilities and technologies. In addition, 
EPA sent a CWA section 308 Questionnaire to the industry to gather 
information characterizing coastal oil and gas pollution control 
technology and the costs of such technologies. The questionnaire and 
results are described below.

A. Information Used From the Offshore Guidelines

    Due to certain similarities in the technologies employed and wastes 
generated by the offshore and coastal subcategories of the oil and gas 
industry, certain data generated during the Offshore Guidelines 
development effort have been utilized in the development of this 
proposed rule where appropriate. Those data most influential in the 
development of this proposed rule, listed below, are summarized both in 
the Coastal Technical Development Document and described in more detail 
in the Development Document for the Effluent Limitations Guidelines and 
New Source Performance Standards for the Offshore Subcategory of the 
Oil and Gas Extraction Point Source Category, (hereafter referred to as 
the Offshore Technical Development Document), Sections V and XVIII 
(EPA, January 1993).
     Produced water characteristics for Cook Inlet.
     Produced water characteristics for effluent from improved 
gas flotation.
     Drilling fluids and cuttings waste characteristics.
     Deck drainage characteristics.
     Domestic waste characteristics.
     Sanitary waste characteristics.
     Some non-water quality environmental impacts.

B. 1993 Coastal Oil and Gas Questionnaire

    A comprehensive questionnaire entitled the ``1993 Coastal Oil and 
Gas 308 Questionnaire'' was developed under the authority of section 
308 of the CWA. EPA distributed this questionnaire to all known coastal 
oil and gas operators. The Questionnaire requested information on oil 
and gas waste generated, their treatment and disposal methods and costs 
for waste treatment and disposal. The questionnaire also requested 
information regarding the financial profile of each operator surveyed.
    Upon their return, EPA reviewed the questionnaires for completeness 
and technical content and then transcribed the responses into a 
computer readable format using double key-entry procedures. EPA 
prepared statistical estimates in order to extrapolate the results from 
the sampled wells and facilities to the entire coastal industry. EPA 
used the individual data and the statistical reports to determine waste 
volumes, treatment and disposal methods and costs of treatment and 
disposal methods. EPA also used the survey results to estimate future 
industrial activity. The statistical analysis of the questionnaire data 
is included in the record for this rulemaking.

C. Investigation of Solids Control Technologies for Drilling Fluids

    In 1993, EPA collected samples and gathered technical data at three 
drilling operations in the coastal region of Louisiana. The purpose of 
this effort was to gather operating and cost information regarding 
closed-loop solids control technology (See description of this 
technology in Section VI.A) at active oil and gas well drilling 
operations. Two of the sites were drilling using land-based rigs, and 
the other operation was located in an inland bay and used a posted 
barge rig. One operator was a large independent, the other 2 were 
majors.1

    \1\The term ``major'' oil and gas company is used here to 
differentiate it from smaller operators in the industry. Major oil 
and gas companies are characterized by a high degree of vertical 
integration, i.e., their activities encompass both ``upstream'' 
activities--oil exploration, development, and production and 
``downstream'' activities--transportation, refining, and marketing. 
As a group the majors generally produce more oil and gas, earn 
significantly more revenue and income, have considerably larger 
assets, and have greater financial resources than the independent 
operators.
    Technical and cost information was collected on the following 
topics:
     Drilling waste volumes and disposal methods.
     Solids control equipment design and performance.
     Drilling fluids.
     Well design and construction.
     Drilling operations.
     Annular injection.
     Miscellaneous waste volumes and disposal methods.
     EPA used the results of this investigation to determine methods 
and costs of drilling waste disposal, as well as miscellaneous waste 
volumes, and their treatment and disposal.

D. Sampling Visits to 10 Gulf of Mexico Coastal Production Facilities

    EPA visited ten coastal oil and gas production facilities located 
in Texas [[Page 9439]] and Louisiana to gather operating and cost 
information regarding produced water injection and to collect samples 
of produced water and miscellaneous wastes. Samples were analyzed for a 
variety of analytes in the categories of organic chemicals, metals, 
conventional and non-conventional pollutants, and radionuclides. 
Sampling at each site was conducted for one day over a span of eight 
hours. Technical and cost data were collected in addition to the 
production waste samples.
    EPA was careful, in its selection of Gulf Coast sites, to visit 
facilities that (1) were located in both Texas and Louisiana, (2) were 
located in different wetland situations (wetlands, or inland bays), and 
(3) that ranged in operator size (major to small independent). Nine of 
the ten facilities visited utilized injection wells for produced water 
disposal and one utilized surface discharge.
    A focus of this site visit program was to investigate the 
technologies used to treat produced waters prior to injection. Several 
of the facilities employed cartridge filtration subsequent to BPT 
treatment (gravity separation sometimes assisted by heat or chemicals).
    Aqueous samples were collected from settling tank effluent at all 
ten facilities, as well as the influent (settling effluent) and 
effluent of all four filtration systems. Samples were analyzed for the 
following analytes:

--TSS
--Oil and Grease
--Volatile Organics
--Semi-volatile Organics
--Metals
--Conventional Parameters
--Non-conventional Parameters
--Radionuclides

    Cartridge filters were also collected at all the facilities that 
utilized them, and were analyzed for radionuclides concentrations. 
Samples of produced sands were also collected where available and 
analyzed for the same pollutants as for produced water.
    In addition to the sampling activities, technical and cost 
information was collected on the following topics:
     Separator and treatment system technologies and 
configuration.
     Equipment space requirements.
     Support structures.
     Miscellaneous waste volumes treatment and disposal 
methods.
     Produced water volumes and disposal methods.
     Energy requirements.
     Injection well remedial work requirements.
     Ancillary equipment requirements (besides the injection 
well) for injection.
     Injection well design and operation.
     Production data.
    The results from this study, together with data from the EPA 1993 
Coastal Oil and Gas Questionnaire and state permit data, discussed 
below, formed the basis for EPA's produced water treatment and disposal 
cost analyses discussed later in Section VI.B. The analytical data was 
used to characterize produced water effluent characteristics from BPT 
treatment systems.

E. State Discharge Monitoring Reports

    EPA obtained detailed information on produced water discharges from 
state discharge permits for operators in Texas and Louisiana. The 
Louisiana Department of Environmental Quality (LADEQ) and the Texas 
Railroad Commission (TRC) supplied EPA with state permits for all known 
dischargers in the coastal areas. The state permit information 
identifies the operator, the name of the producing field, the location 
of the production facility, the volume of produced water discharged, 
the location and permit number of the outfall, and in Louisiana only, 
the compliance date by which the discharge must cease. From these data, 
EPA estimated that 216 production facilities in both the Texas and 
Louisiana coastal region will be discharging after July 1996 (the 
projected date of issuance of this regulation). The list of these 
facilities is presented in the record for the rulemaking. From this 
list EPA estimated costs of produced water treatment and disposal on a 
per facility basis.

F. Commercial Disposal Operations

    In May 1992, EPA visited two non hazardous oil and gas waste land 
treatment facilities and two waste transfer stations in Louisiana. The 
purpose of these visits was to investigate the transportation, 
handling, disposal methods employed and associated costs of these 
operations. Detailed information was gathered concerning the operation 
of the landfarm treatment process used for the disposal of non-
hazardous oil field wastes, transportation equipment, transfer 
equipment, equipment fuel requirements and costs incurred by the 
facilities and costs charged to the customers. The information was used 
in the development of compliance costs and the non-water quality 
environmental impacts for the various regulatory options under 
consideration.
    In March 1992, EPA visited two commercial produced water injection 
facilities in Louisiana. The purpose of the visits was to collect 
information regarding costs of produced water disposal and other 
operating costs as well as to collect samples of produced water, filter 
solids, used filters and tank bottoms solids for radioactivity 
analysis. Both facilities utilized sedimentation and filtration as 
treatment processes for produced water followed by underground 
injection. The technical information gathered at these sites was used 
in developing compliance costs and the non-water quality impacts for 
the various regulatory options under consideration. The results of the 
radioactivity analyses were used in an evaluation of radioactivity 
concentrations in oil and gas wastes.
G. Evaluation of NORM in Produced Waters

    EPA reviewed all known data regarding the presence of naturally 
occurring radioactive materials (NORM) found in discharge of produced 
water and associated with scales and sludges on oil and gas production 
equipment.
    EPA summarized produced water radioactivity data from 22 available 
studies focusing on data from coastal sites. Each of these 22 studies 
was summarized according to the location of the sites, sampling plans, 
and analytical methods used to measure the radionuclides. This 
information was used in characterizing NORM in produced water 
discharges in the Gulf Coast.

H. Alaska Operation

    In August 1993, EPA embarked on a fact-finding mission regarding 
drilling and production operations and practices in both regions of 
Alaska, Cook Inlet and the North Slope. Information and data were 
obtained by direct visits to these areas, and by contacting the Alaska 
Oil and Gas Association (AOGA), state regulatory authorities, and 
individual operators. In addition, AOGA and individual operators 
submitted to EPA information on projects and technologies currently 
being developed and used in Cook Inlet and on the North Slope to 
dispose of drilling and production wastes, and the costs associated 
with these projects. Specific operating and cost information was 
obtained on zero discharge technologies including grinding and 
injection systems for drilling fluids and drill cuttings as well as 
produced water injection. EPA used the information obtained during this 
data gathering effort to estimate costs of treatment and control 
options for Alaska coastal facilities.
    In March 1994, Cook Inlet Alaska oil and gas operators submitted to 
EPA information on drilling waste disposal alternatives and their costs 
and on [[Page 9440]] projected drilling schedules. Three alternatives 
were evaluated by the operators in terms of technological achievability 
and costs: discharge to Cook Inlet surface water, land-based disposal, 
and disposal by injection. EPA considered this information during its 
development of regulatory options and estimation of costs for disposal 
of drilling wastes in Cook Inlet. These same Cook Inlet operators also 
submitted to EPA information on the technological and economic 
feasibility of zero discharge of produced water from the largest shore-
based production facility in the Inlet. This information presented the 
costs and technological achievability for three produced water 
injection alternatives including (1) Treatment and injection at the 
platforms, (2) treatment at onshore treatment facilities (for some 
platform operations) and onshore injection, and (3) treatment at 
onshore treatment facilities and injection back at the platforms. EPA 
considered this information during its development of zero discharge 
option for produced water and cost estimations in Cook Inlet.

I. Region X Drilling Fluid Toxicity Data Study

    EPA evaluated a summary data base containing Region X permit 
compliance monitoring information including toxicity measurements of 
drilling fluids used in Alaska. The database contains 161 records of 
96-hour LC50 data from coastal and offshore oil and gas wells in Alaska 
from 1985 to 1994. Drilling fluid toxicity levels were characterized 
for Alaska drilling activities, and particularly for activities in Cook 
Inlet. This data indicated that drilling fluids and cuttings being 
discharged in Cook Inlet may be able to meet a toxicity limitation of 
between 100,000 ppm (SPP) and 1,000,000 ppm (SPP).
    EPA measures toxicity using a standard bioassay test known as the 
``Drilling Fluids Toxicity Test'' (See 40 CFR 435 Subpart A, Appendix 
2). Under this test, the species mysidopsis bahia is exposed to 
different concentrations of the drilling fluids and cuttings for a set 
time, 96 hours. An LC-50 toxicity test is performed by mixing a 
solution of seawater and drilling fluids and cuttings, allowing the 
solution to settle for one hour, decanting the liquid off from the 
settled solids, and then adding to the decant, or suspended particulate 
phase (SPP), the test organisms and determining the number of organisms 
alive after 96 hours. Then, by observing mortality rates and by 
calculation, the concentration required to kill 50 percent of the test 
animals in 96 hours is determined. The ``96-hour LC-50'' is defined as 
the lethal concentration of a toxicant that will kill 50 percent of the 
test organisms after a 96-hour exposure. Thus, the lower the LC-50 
value, the higher the relative toxicity.

J. California Operations

    EPA visited coastal oil and gas operations in Long Beach Harbor, 
California in February 1992. The visit was to one of the four man-made 
islands that have been constructed in the Harbor for the purpose of oil 
and gas extraction. The facilities on these islands are operated by 
THUMS, a consortium of five oil and gas operating companies (Texaco, 
Humble (now Exxon), Union, Mobil and Shell). EPA met with state 
regulatory officials and was given a tour of one of the islands by 
THUMS personnel. Both drilling and production were occurring at the 
time of the visit.
    Information regarding waste generation, treatment, disposal, and 
costs were obtained during the visit. No discharges are occurring from 
the THUMS operations. The information provided EPA with specific waste 
disposal technology and cost information which has, where appropriate, 
been incorporated into cost analyses, and enabled EPA to characterize 
California coastal oil and gas operations.

K. OSW Sampling Program

    EPA's Office of Solid Waste conducted a sampling program on 
associated oil and gas wastes in 1992. As part of this effort, samples 
were obtained for completion, workover, and treatment fluids. The 
parameters analyzed for were the same as those for produced water 
samples listed previously in Section V.D. EPA has used this data base 
to characterize the discharges of these fluids. Seven samples of 
treatment, workover and completion fluids were collected from 
operations in Texas, New Mexico and Oklahoma. The samples were analyzed 
for conventional, nonconventional and priority pollutants.

L. Estimation of the Inner Boundary of the Territorial Seas

    As part of the Coastal Guidelines development effort, EPA 
specifically delineated the seaward boundary of the coastal subcategory 
(which is the inner boundary of the Territorial Seas). The purpose of 
this effort was to define an area in order to estimate the number of 
coastal wells and production facilities operating in that area. The 
purpose was not to determine a well's subcategory for regulatory permit 
writers. This delineation is in the form of latitude and longitude 
coordinates covering that part of the inner boundary of the Territorial 
Seas along Alaska's North Slope and Cook Inlet, Texas, Louisiana, 
Alabama and Southern California. Much of this boundary has been 
delineated on nautical charts published by the National Ocean Service 
of the National Oceanic and Atmospheric Administration (NOAA). In some 
locations however, this boundary has not previously been delineated by 
NOAA, and EPA completed the coordinates using established procedures 
described in the Convention of the Territorial Seas and the Contiguous 
Zone, Articles 3-13. The digital coordinates of the inner boundary of 
the Territorial Seas, for the above mentioned locations and a 
description of its derivation is included in the record for this rule. 
This digital boundary assisted EPA in its determination of the number 
of wells and production facilities that exist in this subcategory.
VI. Development of Effluent Limitations Guidelines and Standards

A. Drilling Fluids and Drill Cuttings (Drilling Wastes)

1. Waste Characterization
    Drilling fluid and cuttings discharges are typically generated in 
bulk form and occur intermittently during well drilling and at the end 
of the drilling phase.
    There are currently no drilling fluids and cuttings discharges in 
any coastal area except Cook Inlet. In Cook Inlet, operators do not 
currently practice zero discharge, except for a small volume of 
drilling fluids and cuttings wastes (approximately one percent) which 
are not discharged because they do not meet current permit limits. 
Generally, drilling fluids and cuttings volumes average approximately 
14,000 barrels (bbl) per new well drilled in Cook Inlet. (NOTE: The 
barrel is a standard oil and gas measurement and is equal in volume to 
42 gallons). Based on industry projections given to EPA, an average of 
79,000 bbls drilling fluids and cuttings are generated each year (bpy) 
in the Inlet. Significant pollutants in these wastes include chromium, 
copper, lead, nickel, selenium, silver, beryllium and arsenic among the 
toxic metals. Toxic organics present include naphthalene, fluorene, and 
phenanthrene.
    TSS makes up the bulk of the pollutant loadings, part of which is 
comprised of the toxic pollutants. TSS concentrations are very high due 
to the nature of the wastes. And because its TSS concentration is so 
high, discharges of drilling fluids and cuttings can cause 
[[Page 9441]] reduced light penetration resulting in decreased sea life 
primary productivity, fish kills or reduced growth rate, interference 
in development of fish eggs and larvae, modifications of fish movement 
and migration, and reduction of the abundance of food available to 
fish. Benthic smothering from settleable materials results in potential 
damage to invertebrate populations and potential alterations in 
spawning grounds and feeding habitats.
    Operators use solids control equipment to remove drill cuttings 
from the drilling fluid systems which allows drilling fluids to be 
recycled and reduces the total amount of drilling wastes generated. 
Depending on the drilling solids control system and the method of waste 
storage and disposal onsite, a small wastestream, termed ``dewatering 
effluent'' may be segregated from the drilling fluids and cuttings. 
Dewatering effluent may be discharged from reserve pits or tanks which 
store drilling wastes for reuse or disposal. Dewatering effluent may 
also be generated in enhanced solids control systems. Enhanced solids 
control systems, also known as closed-loop solids control operations, 
remove solids from the drilling fluid at greater efficiencies than 
conventional solids removal systems. Increased solids removal 
efficiency minimizes the buildup of drilled solids in the drilling 
fluid system, and allows a greater percentage of drilling fluid to be 
recycled. Smaller volumes of new or freshly made fluids are required as 
a result. An added benefit of the closed-loop technology is that the 
amount of waste drilling fluids can be significantly reduced. The 
installation of reserve pits is unnecessary in closed-loop systems for 
this reason. Dewatering effluent is generated in the process of 
drilling fluids solids removal and can either be reused (it often 
contains expensive reusable chemicals), or disposed of.
    EPA's general permit for drilling operations for TX and LA included 
limitations for the discharge of dewatering effluent (See Section 
VI.E). However, the 1993 Coastal Oil and Gas Questionnaire results show 
that few operators discharge dewatering effluent as a separate 
wastestream. Additionally, contacts with industry indicate that the 
volume of dewatering effluent from reserve pits is small if nonexistent 
as the use of pits is phasing out due to state permit conditions, 
environmental or land owner concern, or the expanding use of closed-
loop systems. EPA site visits to drilling operations, where these 
closed-loop systems were in place, showed that none of the dewatering 
effluent was discharged. Instead, it is either recycled, or sent with 
other drilling wastes to commercial disposal. Operators at these 
facilities explained that it is less expensive to send this wastestream 
along with drilling fluids and drill cuttings for onshore disposal 
rather than to treat for discharge.
2. Selection of Pollutant Parameters
    a. Pollutants Regulated
    In the coastal subcategory, EPA is proposing to establish BAT, 
NSPS, and pretreatment standards that would require zero discharge of 
drilling fluids and drill cuttings. Where zero discharge is required, 
EPA would be controlling all pollutants in the wastestream.
    EPA is also considering an alternative BAT limit applicable only to 
Cook Inlet, that in addition to the BPT requirement prohibiting the 
discharge of free oil, would also prohibit the discharge of diesel oil 
and limit toxicity and specify the cadmium and mercury content in stock 
barite. As presented in Section VI of the Offshore Technical 
Development Document, the prohibitions on the discharge of free oil and 
diesel oil would effectively remove toxic, nonconventional, and 
conventional pollutants. Diesel oil and free oil are considered, under 
BAT and NSPS, to be ``indicators'' for the control of specific toxic 
pollutants present in the complex hydrocarbon mixtures used in drilling 
fluid systems. These pollutants include benzene, toluene, ethylbenzene, 
naphthalene, phenanthrene, and phenol. Additionally, diesel oil may 
contain from 20 to 60 percent by volume polynuclear aromatic 
hydrocarbons (PAH's) which constitute the more toxic components of 
petroleum products.
    Control of diesel oil would also result in the control of 
nonconventional pollutants under BAT and NSPS. Diesel oil contains a 
number of nonconventional pollutants, including PAHs such as 
methylnaphthalene, methylphenanthrene, and other alkylated forms of the 
listed organic priority pollutants.
    EPA is proposing to establish BCT limitations for drill fluids and 
drill cuttings that would prohibit discharge of free oil (using the 
static sheen test) for Cook Inlet, and would require zero discharge 
everywhere else. The prohibition on the discharge of free oil (in 
addition to the zero discharge requirement) would effectively reduce or 
eliminate the oil and grease in these discharges. EPA is limiting free 
oil under BCT as a surrogate for oil and grease in recognition of the 
complex nature of the oils present in drilling fluids, including crude 
oil from the formation being drilled.
    Prohibiting the discharge of diesel oil and free oil eliminates 
discharges of the above-listed constituents, to the extent that these 
constituents are present in either of these two parameters, and reduces 
the level of oil and grease present in the discharged drilling fluids 
and cuttings. Also under this alternative option, limitations on 
cadmium and mercury content in barite would control toxic and 
nonconventional pollutants in drilling fluids and cuttings discharges. 
This limitation would indirectly control the levels of toxic pollutant 
metals because cleaner barite that meets the mercury and cadmium limits 
is also likely to have reduced concentrations of other metals. 
Evaluation of the relationship between cadmium and mercury and the 
trace metals in barite shows a correlation between the concentration of 
mercury with the concentration of arsenic, chromium, copper, lead, 
molybdenum, sodium, tin, titanium and zinc (See the Offshore Technical 
Development Document in Section VI).
    Toxicity of drilling fluids and cuttings is being regulated as a 
nonconventional pollutant that controls certain toxic and 
nonconventional pollutants. It has been shown, during EPA's development 
of the Offshore Guidelines, that control of toxicity encourages the use 
of less toxic, water-based drilling fluids, and where absolutely 
necessary, the use of less mineral oil added to a drilling fluid (and 
the pollutants, such as the PAH's, identified as constituents of 
mineral oil). A toxicity limitation would thus encourage the use of the 
lowest toxicity drilling fluids and the use of low-toxicity drilling 
fluid additives.
    b. Pollutants Not Regulated.
    Where zero discharge would be required, all pollutants would be 
controlled in drilling fluids and cuttings discharges. Where discharges 
with limitations would be required, (specifically if EPA selected the 
alternative BAT option in Cook Inlet), EPA has determined that it is 
not technically feasible to specifically control each of the toxic 
constituents of drilling fluids and cuttings that are controlled by the 
limits on the pollutants proposed for regulation.
    EPA has determined that certain of the toxic and nonconventional 
pollutants are not controlled by the limitations on diesel oil, free 
oil, toxicity, and mercury and cadmium in stock barite. EPA exercised 
its discretion not to regulate these pollutants because EPA did not 
detect these pollutants in more than a very few of the samples from 
EPA's field sampling program and does not believe them to be found 
throughout the [[Page 9442]] industry; the pollutants when found are 
present in trace amounts not likely to cause toxic effects; and due to 
the large number and variation in additives or specialty chemicals that 
are only used intermittently and at a wide variety of drilling 
locations, it is not feasible to set limitations on specific compounds 
contained in additives or specialty chemicals.
3. Control and Treatment Technologies
    a. Current Practice.
    BPT effluent limitations guidelines for coastal drilling fluids and 
drill cuttings prohibit the discharge of free oil (using the visual 
sheen test). However, because of either EPA general permits, state 
requirements, or operational preference, no drilling fluids and 
cuttings discharges are occurring in the North Slope, the Gulf coast 
states, or California. The only coastal operators discharging drilling 
fluids and cuttings are located in Cook Inlet. In Cook Inlet, neither 
diesel nor mineral-oil-based drilling fluids or resultant cuttings may 
be discharged to surface waters because they have been shown to cause a 
visible sheen upon the receiving waters. Compliance with the BPT 
limitations may be achieved either by product substitution 
(substituting a water-based fluid for an oil-based fluid), recycle and/
or reuse of the drilling fluid, or by onshore disposal of the drilling 
fluids and cuttings at an approved facility.
    NPDES permits issued by EPA for Cook Inlet drilling operations have 
also included BAT limitations based on ``best professional judgement'' 
(BPJ). The permit requirements allow discharges of drilling fluids and 
drill cuttings provided certain limitations are met including a 
prohibition on the discharges of free oil and diesel oil, as well as 
limitations on mercury, cadmium, toxicity and oil content. (See Section 
IV.E for a summary of the permits). Operators may employ any number of 
the following waste management practices to meet those permit 
limitations:
    * Product substitution--to meet prohibitions on free oil and diesel 
oil discharges, as well as the toxicity and/or clean barite 
limitations,
    * Onshore treatment and/or disposal of drilling fluids and drill 
cuttings that do not meet the toxicity or clean barite limitations,
    * Waste minimization--enhanced solids control to reduce the overall 
volume of drilling fluids and drill cuttings, and
    * Conservation and recycling/reuse of drilling fluids.
    Refer to the Coastal Technical Development Document, Sections VII-
VIII for a detailed discussion of each of these waste minimization 
techniques.
    b. Additional Technologies Considered.
    EPA has evaluated an additional method for drilling fluid and 
cuttings control and treatment in order to achieve zero discharge: 
namely, grinding and injection of drilling wastes. This process 
involves the grinding of the drilling fluids and drill cuttings into a 
slurry that can be injected into a dedicated disposal well. The 
grinding system consists of a vibrating ball mill which pulverizes the 
cuttings and creates an injectable slurry. Recent information has shown 
that this comparatively contemporary technology has been successfully 
demonstrated on the North Slope for drilling waste disposal, and is 
being introduced both in the Gulf Coast coastal areas as well as in 
Cook Inlet. EPA, therefore believes that this technology is available 
to coastal operators.
    In addition to grinding and injection, EPA has also investigated 
the feasibility of onshore disposal of this wastestream. For the 
coastal subcategory drilling activities, in areas other than Cook 
Inlet, current permits or practice (in the case of the North Slope) 
require zero discharge of drilling fluids and cuttings. On-land 
disposal sites located in Alaska are available in these areas and are 
being utilized to comply with the zero discharge requirement. On-land 
disposal sites are also available to two out of the five Cook Inlet 
operators. These two operators jointly operate an oil and gas landfill 
disposal site on the west side of the Inlet. Using projected drilling 
schedules provided by industry, EPA estimated that these two operators 
would generate approximately 76 percent of the drilling wastes produced 
by the Cook Inlet operators over the next seven years following the 
scheduled 1996 promulgation of this rule. EPA has determined that there 
is sufficient on-land disposal capacity to accept all of the drilling 
fluids and cuttings generated by these two operators at this disposal 
facility.
    EPA investigated the logistical difficulties of storing and 
transporting drilling wastes in the Cook Inlet, due to the extensive 
tidal fluctuations, strong currents, and ice formation during winter 
months. While these climatological and tidal situations may cause 
complications, EPA has determined that they do not pose insurmountable 
technical barriers. EPA has taken into consideration supplementary 
costs incurred by additional winter transportation and storage of 
drilling wastes in its cost evaluation of the zero discharge 
requirement as described later in Section VI.A.
    No on-land oil and gas waste disposal facilities are available in 
Alaska to the other three Cook Inlet operators who plan to drill after 
promulgation of this rule. EPA investigated the possibility of 
disposing of drilling wastes at an on-land oil and gas waste disposal 
site available to Cook Inlet operators located in Idaho. EPA determined 
that, while it is generally more economical to dispose of drill wastes 
via grinding and injection, in the case of smaller volumes of drilling 
wastes, it would be more cost effective to dispose of the wastes by 
shipping them to the Idaho disposal facility.
    Land disposal of oil and gas wastes is also available to Cook Inlet 
operators at a disposal facility located in Oregon. EPA performed its 
costing of land disposal assuming the use of the Idaho facility (see 
discussion of costs later in this section). EPA expects that costs to 
dispose of the wastes at the Oregon facility would be close to or less 
than costs using the Idaho facility because transportation of wastes to 
the Oregon facility would utilize barging to a greater extent, making 
overall transportation costs less.
    The results of this investigation show that the volume of drilling 
fluids and drill cuttings wastes generated in Cook Inlet can be either 
disposed of on-land or by grinding and injection. However, during the 
previous Offshore Guidelines rulemaking affecting Alaska offshore 
drilling operations, and early in the data gathering stages of this 
proposed rule, operators raised concerns that compliance with zero 
discharge could significantly interfere with drilling operations. EPA 
does not have sufficient information supporting these concerns, and 
solicits comments on these issues.
    Therefore, for this proposal, EPA is also considering options which 
would allow the discharge of the drilling fluids and drill cuttings in 
Cook Inlet providing they were to meet certain limitations. These 
limitations would prohibit the discharge of diesel oil and free oil 
using the static sheen test, limit cadmium and mercury in the stock 
barite used in fluid compositions and toxicity at either 30,000 ppm 
(SPP) or a more stringent toxicity in range of 100,000 ppm (SPP) to 1 
million ppm (SPP). Drilling fluids and drill cuttings not meeting these 
limitations would not be allowed to be discharged, and therefore, would 
have to be injected or sent to shore for disposal. EPA would base the 
more stringent toxicity limitations (based on further evaluation as 
discussed below), in part, on the volume of drilling wastes it 
determines [[Page 9443]] could be injected or disposed of onshore 
without interfering with ongoing drilling operations.
    Prior to, and during the offshore rulemaking, EPA conducted 
bioassay tests on eight generic mud types (encompassing virtually all 
water-based muds, exclusive of specialty additives, primarily used on 
the outer continental shelf), and, EPA established a toxicity 
limitation of 30,000 ppm (SPP). Even in offshore Alaska, drilling was 
not evaluated for specific locations, thus technical drilling 
requirements for adequate drilling with a focus on small localized 
areas were not considered in setting the limitation for the offshore 
rule. One alternative option for the coastal rule would be to set the 
limitations for Cook Inlet equal to the offshore limitations for 
Alaska.
    As discussed above, another option would retain the offshore 
limitations but require a more stringent toxicity requirement. The 
toxicity limit would be based on a relationship between the achievable 
toxicity of the drilling wastes and the volume of these wastes that 
could be disposed of onshore or by grinding and injection without 
interfering with ongoing drilling operations (e.g., some fraction of 
the volume of wastes generated and covered by the zero discharge 
option).
    In order to determine the appropriate toxicity level for the more 
stringent toxicity option, EPA attempted to evaluate effluent toxicity 
test results for Cook Inlet drilling fluids and cuttings discharges. 
EPA reviewed permit compliance monitoring records, from EPA's Region 
10, containing 161 sets of results for toxicity testing of drilling 
fluids and drill cuttings used in the Alaska offshore and coastal 
regions between 1985 and 1994. (The measure of toxicity is a 96 hour 
test that estimates the concentration of drilling fluids suspended 
particulate phase (SPP) that is lethal to 50 percent of the test 
organisms.) The records were summarized into a database which was 
evaluated on the basis of the toxicity of drilling fluids and drill 
cuttings used in Alaska as a whole and Cook Inlet in particular. After 
sorting the database to eliminate inadequate data, such as drilling 
fluids contaminated by pills and incomplete toxicity tests, 104 sets of 
results were retained for all of Alaska, with 59 of these from Cook 
Inlet.
    Of the Cook Inlet bioassay test results, 83 percent were less toxic 
than 100,000 ppm (SPP); 60 percent were less toxic than 500,000 ppm; 
and one percent exhibited no toxic effect (i.e., 1 million ppm or 
greater with less than 50 percent mortality of the test organism). 
(Note that toxicity is inversely related to the 96-hour bioassay 
results so as the values cited above increase, toxicity decreases).
    These evaluations utilized an available database obtained from 
EPA's Region 10, which provides an account of the relationship between 
toxicity and drilling fluids currently being discharged. The toxicity 
values are identified in the available database by operator, permit 
number, well name, date and base fluids system (mud). In addition, some 
of the values are related to an identified volume of muds discharged. 
However, many of the values in the summary do not have either a volume 
identified or whether the drilling fluids were discharged. This 
available database is presently being updated as EPA continues to 
identify the volume of drilling wastes having been discharged in Cook 
Inlet related to specific toxicity test results. EPA solicits any 
information useful in determining an appropriate toxicity limitation 
that individual Cook Inlet operators have including data on the 
specific amounts of drilling wastes generated versus discharged and 
their corresponding toxicity test results.
4. Options Considered
    EPA has developed three options for the control and treatment of 
drilling fluids and drill cuttings. As mentioned earlier in this 
preamble, dewatering effluent may be a wastestream generated 
separately. However, because it consists of constituents that originate 
entirely within the drilling fluids and cuttings solids control system, 
EPA will not be regulating dewatering effluent separately. Rather, EPA 
proposes to make the drilling fluids and cuttings options applicable to 
the dewatering effluent wherever this wastestream may be generated.
    The three options considered by EPA contain zero discharge for all 
areas, except two of the options contain allowable discharges for Cook 
Inlet. One of these options which would allow discharges meeting a more 
stringent toxicity limitation would require an additional notice for 
public comment since the specific toxicity limitation has not been 
determined at this time (as discussed in this section). The three 
options are:

Option 1: Zero discharge for all areas except Cook Inlet where 
discharge limitations require toxicity of no less than 30,000 ppm 
(SPP), no discharge of free oil and diesel oil and no more than 1 mg/1 
mercury and 3 mg/1 cadmium in the stock barite.
Option 2: Zero discharge for all areas except for Cook Inlet where 
discharge limitations would be the same as Option 1, except toxicity 
would be set to meet a limitation between 100,000 ppm (SPP) and 1 
million ppm (SPP).
Option 3: Zero Discharge for all areas.

    As discussed later in this section, all of the above options are 
being co-proposed.
    Option 1 would require zero discharge of drilling fluids and 
cuttings for all coastal drilling operations except those located in 
Cook Inlet. Allowable discharge limitations for drilling fluids and 
cuttings in Cook Inlet would require compliance with a toxicity value 
of no less than 30,000 ppm (SPP); no discharge of free oil (as 
determined by the static sheen test); no discharge of diesel oil and 1 
mg/kg of mercury and 3 mg/kg of cadmium in the stock barite. (These are 
the same limitations as those for offshore drilling operations waste 
discharges in the Alaska.)
    Option 2 would require all operators to meet the same zero 
discharge limitation for the drilling fluids and cuttings in all areas 
except for Cook Inlet. In Cook Inlet, the drilling fluids and cuttings 
discharges would be required to meet the same limitations as in Option 
1 except that a more stringent toxicity limitation would be imposed. 
Instead of meeting a toxicity limitation of 30,000 ppm (SPP), a 
toxicity limitation between 100,000 ppm (SPP) and 1 million ppm (SPP) 
would be met.
    The toxicity limitation range of between 100,000 ppm (SPP) and one 
million ppm (SPP) reflects the range of toxicity measurements resulting 
from EPA's evaluation of the current practice for drilling in Cook 
Inlet. As discussed previously in this section, an attempt was made in 
this evaluation to determine the volumes of drilling wastes being 
discharged and their respective toxicity levels. Because of the lack of 
identified discharge volumes for some of the toxicity test results, 
this determination could not be completed. Using the 83 percent of 
drilling wastes which reflects the fraction of test results less toxic 
than 100,000 ppm (SPP), and coincidentally also reflects the fraction 
of identified volumes less toxic than one million ppm (SPP), costs and 
discharge loadings were developed for this option. (The method used to 
derive this range is separate and distinct from the statistical 
methodologies generally used by EPA in effluent guidelines regulations 
to derive 30-day average and daily maximum limitations calculated from 
the 95th and 99th percentiles, respectively.) However, due to the above 
discussed limitations with the data base, EPA is currently only able to 
estimate an achievable toxicity limit in the range of 100,000 ppm (SPP) 
to one million ppm (SPP). As described earlier under 
[[Page 9444]] ``Additional Technologies Considered'' of this section, 
EPA is continuing to evaluate toxicity test results and volumes and any 
other data for drilling fluids used and discharged in Cook Inlet in an 
effort to derive a more specific limitation and resulting revisions of 
costs and loadings. A supplemental notice presenting the data and 
revised results and soliciting comment would be necessary prior to 
promulgation.
    Option 3 would prohibit the discharge of drilling fluids and 
cuttings from all coastal oil and gas drilling operations. This option 
utilizes grinding and injection and onshore disposal as a basis for 
complying with zero discharge of drilling fluids and cuttings.
    The technology Options 1 and 2 for Cook Inlet have been developed 
taking into consideration the possibility that Cook Inlet operations 
are unique to the industry due to a combination of climate, 
transportation logistics, and structural and space limitations that 
interfere with the drilling operations. These options are based on a 
degree of recycling and reuse, onshore disposal and/or grinding and 
injection of a portion of the wastes if they cannot meet the 
limitations, in addition to product substitution in order to attain the 
limitations and be able to discharge a portion of the generated wastes.
    EPA solicits comments on the two discharge options containing 
specific data on the toxicity levels achievable for drilling fluids 
compositions and drill cuttings and why the more toxic of the 
compositions must be used in order to successfully drill. Also, 
information is solicited on the degree to which zero discharge all 
would interfere with drilling operations in Cook Inlet, given the 
estimate of a limited amount of drilling planned.
5. BCT Options Selection
a. BCT Cost Test Methodology.
    The methodology for determining ``cost reasonableness'' was 
proposed by EPA on October 29, 1982 (47 FR 49176) and became effective 
on August 22, 1986 (51 FR 24974). These rules set forth a procedure 
which includes two tests to determine the reasonableness of costs 
incurred to comply with candidate BCT technology options. If all 
candidate options fail either of the tests, or if no candidate 
technologies more stringent than BPT are identified, then BCT effluent 
limitations guidelines must be set at a level equal to BPT effluent 
limitations. The cost reasonableness methodology compares the cost of 
conventional pollutant removal under the BCT options considered with 
the cost of conventional pollutant removal at publicly owned treatment 
works (POTWs).
    BCT limitations for conventional pollutants that are more stringent 
than BPT limitations are appropriate in instances where the cost of 
such limitations meet the following criteria:
     The POTW Test: The POTW test compares the cost per pound 
of conventional pollutants removed by industrial dischargers in 
upgrading from BPT to BCT candidate technologies with the cost per 
pound of removing conventional pollutants in upgrading POTWs from 
secondary treatment to advanced secondary treatment. The upgrade cost 
to industry must be less than the POTW benchmark of $0.53 per pound 
($0.25 per pound in 1976 dollars indexed to 1992 dollars).
     The Industry Cost-Effectiveness Test: This test computes 
the ratio of two incremental costs. The ratio is also referred to as 
the industry cost test. The numerator is the cost per pound of 
conventional pollutants removed in upgrading from BPT to the BCT 
candidate technology; the denominator is the cost per pound of 
conventional pollutants removed by BPT relative to no treatment (i.e., 
this value compares raw wasteload to pollutant load after application 
of BPT). The industry cost test is a measure of the candidate 
technology's cost-effectiveness. This ratio is compared to an industry 
cost benchmark, which is based on POTW cost and pollutant removal data. 
The benchmark is a ratio of two incremental costs: the cost per pound 
to upgrade a POTW from secondary treatment to advanced secondary 
treatment divided by the cost per pound to initially achieve secondary 
treatment from raw wasteload. The result of the industry cost test is 
compared to the industry Tier I benchmark of 1.29. If the industry cost 
test result for a considered BCT technology is less than the benchmark, 
the candidate technology passes the industry cost-effectiveness test. 
In calculating the industry cost test, any BCT cost per pound less than 
$0.01 is considered to be the equivalent of de minimis or zero costs. 
In such an instance, the numerator of the industry cost test and 
therefore the entire ratio are taken to be zero and the result passes 
the industry cost test.
    These two criteria represent the two-part BCT cost reasonableness 
test. Each of the regulatory options was analyzed according to this 
cost test to determine if BCT limitations are appropriate.
    b. BCT Cost Calculations and Options Selection.
    (i) Other than Cook Inlet.
    In addition to considering setting the BCT limitations equal to 
BPT, EPA considered two additional BCT options for control of 
conventional pollutants in drilling fluids and drill cuttings. Both of 
these options would require zero discharge of drilling fluids and drill 
cuttings throughout the subcategory except in Cook Inlet. Because all 
operators throughout the entire subcategory, except in Cook Inlet, are 
currently meeting a zero discharge requirement, or in the case of 
dewatering effluent, are practicing zero discharge already, there is 
zero cost and zero removal of conventional pollutants for this 
limitation. Thus, EPA has determined that zero discharge passes the BCT 
cost tests and other statutory factors and proposes a BCT limitation 
equal to zero discharge for all areas except Cook Inlet.
    (ii) Cook Inlet.
    In Cook Inlet, EPA considered either zero discharge (Option 3, 
above), or allowing discharge based on requirements identified in 
Option 2, above. EPA did not consider Option 1 for Cook Inlet, allowing 
discharge at the current Offshore Guidelines limitations with a 
toxicity limit of 30,000 ppm (SPP), as a distinct BCT option because 
the amount of removal of the conventional pollutant oil and grease, as 
oil, from discharge by this level of toxicity could not be determined 
from that removed by the current BPT requirement of no free oil.
    The POTW test (first part of the two part cost-reasonableness test) 
is calculated by comparing the cost per pound of conventional pollutant 
removed in upgrading from BPT to the BCT candidate options. EPA 
determined the costs of each BCT option for drilling fluids, drill 
cuttings, and drilling fluids and drill cuttings combined.
    EPA included only oil and grease and TSS in the BCT analysis. EPA 
did not include BOD because it is not a parameter normally measured in 
wastewaters from this industry since it is associated with the oil 
content, e.g., oil and grease measurement. The use of BOD and oil and 
grease would result in double-counting, thus giving erroneous results. 
EPA did not include the parameter of settleable solids in the BCT 
analysis because settleable solids are not a conventional pollutant.
    EPA calculated cost of the BPT limitations for drilling fluids and 
drill cuttings for Cook Inlet using the model well characteristics and 
disposal costs used for the offshore wells (in the development of the 
Offshore Guidelines). The volume of wastes (drilling fluids and 
cuttings) was based on the 1993 Coastal Oil and Gas Questionnaire data 
for Cook Inlet. EPA based the costs associated with meeting 
[[Page 9445]] the BPT requirement of ``no free oil'' on land-based 
disposal of oil-based drilling fluids and oil laden cuttings and 
substitution of mineral oil for diesel oil in pills. As was done in the 
Offshore Guidelines BCT determinations, oil content, which is normally 
measured in drilling wastes, was used as surrogate for the oil and 
grease conventional pollutant in the calculation of pollutant removals. 
The following are annual BPT costs and conventional pollutant removals 
per well for drilling fluids and cuttings:

Annual Cost (1992 Dollars):
    Drilling Fluids--$40,275
    Drill Cuttings--$22,355
TSS Removals (Annual):
    Drilling Fluids--267,911 pounds
    Drill Cuttings--297,880 pounds
Oil and Grease Removals (Annual):
    Drilling Fluids--207,584 pounds
    Drill Cuttings--92,895 pounds

    The three options for Cook Inlet were evaluated according to the 
BCT cost reasonableness tests. The pollutant parameters used in this 
analysis were total suspended solids and oil and grease. All options, 
except the ``BPT'' option, no discharge of free oil, fail the BCT cost 
reasonableness test. Costs for the ``BPT'' option are equal to zero 
because it reflects current practice. The results of the POTW test 
(first part of the BCT cost test) for the zero discharge option (Option 
3) is $0.151 per pound of conventional pollutant removed. A value of 
less than $0.534 per pound (1992$) is required to pass the POTW test. 
Thus, this option passes the POTW test. The results of the Industry 
Cost Ratio Test (ICR) is 2.097. As this value of 2.097 is greater than 
1.29, zero discharge for drilling fluids and drill cuttings in Cook 
Inlet fails the second test. Thus, EPA proposes that BCT be equal to 
BPT for drilling fluids and drill cuttings discharges in Cook Inlet.
    EPA conducted the same set of tests for Option 3 for the separate 
wastestreams of drilling fluids and cuttings. The results of the BCT 
cost tests for Option 2 and 3 are contained in Table 3 of the preamble, 
show that drilling fluids fail the second test, and cuttings pass. 
(Results for Option 1 are equal to zero and are not shown on Table 3).
    The same set of tests are conducted for the Option 2, prohibitions 
on the discharge of free oil and diesel oil, limitations on cadmium and 
mercury in stock barite and toxicity limitation of between 100,000 and 
1 million ppm (SPP) or greater. For the purpose of conducting these 
calculations, a volume fraction of 0.83 (83 percent) of the drilling 
fluids and cuttings was anticipated to comply with a toxicity 
limitation of between 100,000 ppm (SPP) and 1 million ppm (SPP). A 
summary of the results of these tests, also presented in Table 4, 
demonstrate drilling fluids and cuttings both fail the cost test. Thus, 
both candidate BCT options fail the ICR test, and BCT is set equal to 
Option 1 for this proposal which is equal to zero discharge everywhere 
except for Cook Inlet where BPT would apply.
    The specific calculation of these BCT cost reasonableness tests for 
the drilling fluids and drill cutting options for Cook Inlet are 
discussed further in the Coastal Technical Development Document.

                                Table 4.--BCT Cost Test Results for Drilling Fluids and Drill Cuttings for Cook Inlet\1\                                
--------------------------------------------------------------------------------------------------------------------------------------------------------
                               Pollutant    Compliance                                                                                                  
      Regulatory option       removal (lb/ cost\1\ ($/  BCT cost ($/     Pass POTW (<0.534)\2\     BPT cost ($/  ICR ratio         Pass ICR (<1.29)     
                                 well)        well)         lb)                                        lb)                                              
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                    Drilling Fluids                                                                     
                                                                                                                                                        
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 2....................      191,693      129,026        0.673  No..........................        0.085  ...........  ...........................
Option 3....................    1,127,603      418,888        0.371  Yes.........................        0.085        4.365  No.                        
                                                                                                                                                        
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                     Drill Cuttings                                                                     
                                                                                                                                                        
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 2....................      389,756       30,226        0.078  Yes.........................        0.057        1.368  No.                        
Option 3....................    2,292,681       98,258        0.043  Yes.........................        0.057        0.754  Yes.                       
                                                                                                                                                        
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                              Drilling Fluids and Cuttings                                                              
                                                                                                                                                        
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 2....................      581,449      159,252        0.274  Yes.........................        0.072        3.806  No.                        
Option 3....................    3,420,284      517,146        0.151  Yes.........................        0.072        2.097  No.                        
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\Results of Option are equal to zero and are not shown in this table.                                                                                 
\2\Compliance Cost and Conventional Pollutants Removal are incremental to BPT.                                                                          
\3\1986 benchmark (0.46) adjusted to 1992 dollars $0.534.                                                                                               

6. BAT and NSPS Options
    EPA is co-proposing all three options considered for the BAT and 
NSPS level of control for drilling fluids and drill cuttings. A 
discussion of the costs and impacts and description of the selection 
rationale is contained below.
    a. Costs.
    No costs would be incurred by the industry to comply with Option 1 
because the requirements are reflective of current practice. Costs 
incurred by the coastal industry to comply with Option 2 would amount 
to approximately $1.4 million annually. These costs are attributed only 
to the Cook Inlet operators who would be required to meet the Offshore 
limitations and a more stringent toxicity limitation based on an 
estimate that 83 percent of the drilling fluids and drill cuttings 
would pass a toxicity limitation of between 100,000 ppm (SPP) and 
1,000,000 ppm (SPP). Thus, 17 percent of the drilling wastes would need 
to be disposed of either onshore or by grinding and injection.
    Costs to comply with Option 3 (zero discharge all) are attributed 
only to Cook Inlet operators not currently meeting a zero discharge 
requirement for drilling fluids and drill cuttings (all other coastal 
operators including the North Slope of Alaska are already practicing 
zero discharge). Costs to comply with this option are estimated to be 
approximately $3.9 million annually for Cook Inlet operators. EPA 
conducted an extensive analysis of possible waste disposal options 
available to Cook Inlet operators in order to estimate the costs to 
comply with a zero discharge requirement. The basis for this cost 
analysis is that approximately 76 percent of the drilling fluids and 
[[Page 9446]] cuttings generated in Cook Inlet would be hauled to shore 
for disposal onshore, and the other 24 percent would be injected 
following grinding, into dedicated disposal wells regulated by the 
Underground Injection Control (UIC) program.
    Of the five Cook Inlet operators, two operators generate about 76 
percent of the drilling fluids and drill cuttings in Cook Inlet and, 
have access to a landfill in Alaska. One operator has no future plans 
to drill. The remaining two operators, who generate about 24 percent of 
the drilling wastes, would be expected to, for costing purposes, grind 
and inject to comply with the zero discharge requirement. Out of the 
five Cook Inlet operators, information obtained by EPA in 1993 
indicated that one of them had no plans to drill in the Inlet. Recent 
(1995) information from an additional Cook Inlet operator relates that 
this operator also no longer has plans to drill in the Inlet. EPA 
conservatively estimated that this operator would have drilled six new 
wells (out of a total of 36 for all of the Cook Inlet operators) in the 
next seven years. Due to the fact that this is very recent information, 
the cost and economic analyses presented in this preamble have not 
deleted these six drillings. Thus, the analysis was performed assuming 
only one operator, instead of two, operators will not be drilling. 
However, retaining these six drillings in the analyses will not only 
provide a conservative estimate of the costs and economic impacts, but 
may serve to cover future changes in oil and gas activity should 
decisions be made to resume drilling.
    Costs for land disposal include water vessel transportation, 
storage prior to transport to the disposal facility, truck 
transportation to the disposal facility, and landfill disposal costs. 
Costs for grinding and injection include purchase or rental of the 
grinding, slurrying and pumping equipment, and costs to drill dedicated 
injection wells at the drill site.
    To determine the volume of drilling wastes requiring disposal, EPA 
obtained the projected drilling schedules for the Cook Inlet operators 
using information from the 1993 Coastal Oil and Gas Questionnaire and 
contacts with industry. EPA's projections estimate that 36 new wells 
and 19 recompletions will be drilled in the seven years following 
scheduled promulgation of this rule. (Recompletions are drilling 
operations which utilize an existing well but drill to a deeper 
formation than that which the well was previously producing from). 
Using information about the volume of drilling fluids and drill 
cuttings generated per well, and the projected amount of drilling over 
the seven years following scheduled promulgation, EPA estimates that 
the total amount of drilling fluids and cuttings annually discharged 
from these drilling operations will be approximately 79,000 barrels.
    EPA also considered the logistical difficulties of transporting 
drilling wastes in the Cook Inlet as part of in EPA's costing analysis 
of the options. To achieve zero discharge, certain platforms would 
transport drill wastes to the eastern side of Cook Inlet by supply boat 
during ice conditions, and store the wastes at a transfer station until 
they could be transported by barge to an existing landfill facility on 
the west side of the Inlet. During the summer months, transport of 
wastes would be accomplished by barge directly to the west side.
    Costs for the two operators to dispose of their wastes in the 
Alaskan landfill average $39/barrel. Costs for the other two operators 
(one operator has no future plans to drill) to dispose of their wastes 
by grinding and injection average $53/bbl. A weighted average for 
disposal of 76 percent of the drilling wastes by Alaskan landfills and 
24 percent by grinding and injection equates to $42/bbl. On a per well 
basis, this amounts to approximately $425,000 and $600,000 for each 
recompletion and new well drilled, respectively.
    The costs to comply with Option 2 are approximately $1.4 million 
annually. Capital expenditures are close to those incurred to meet 
Option 3 due to the fact that most operators will be required to 
install the same equipment regardless of the amount of wastes requiring 
disposal. The economic impact analysis associated with this option 
would result in a 1.3 percent reduction in the estimated lifetime 
production for the existing platforms in Cook Inlet as a result of 
three wells not being drilled. The net present value of this production 
loss (reduction in producers' net income) is $263,000 or less than 0.1 
percent of baseline net present value. The average well life decreases 
by 0.2 years as a result of this option.
    The results of the economic impact analysis associated with the 
costs for the zero discharge all option (Option 3) for drilling fluids 
and cuttings show a 2.7 percent reduction in the estimated lifetime 
production for the existing platforms in Cook Inlet (an additional 2.6 
percent over Option 2). The associated net present value loss of 
production is approximately $6.1 million. This is reflective of the 
estimate that Cook Inlet platforms may close on average, 11 months 
earlier than their projected average lifetime of 11 years without this 
requirement. There are no well or platform shutdowns or barriers to new 
drilling activities as a result of these costs. However, three new 
wells would not be drilled. The results of the economic impact analysis 
are discussed in Section VII of the preamble. For new sources, EPA 
expects that the costs of complying with NSPS would be equal to or less 
than those for existing sources.
    An analysis of non-water quality environmental impacts for BAT and 
NSPS was performed. The estimated impacts for the options are discussed 
in Section VIII of the preamble. The increased energy use and air 
emissions and availability of land disposal sites and capacity are 
identified.
    b. Rationale for Option Selection.
    EPA has not selected a preferred option for control of drilling 
fluids and drill cuttings under BAT and NSPS but, rather is co-
proposing all three options. EPA has determined, based on available 
information, that all three options are technologically and 
economically achievable and have acceptable non-water quality impacts. 
However, due to possible operational interferences (for Option 3), the 
lack of sufficient data to set a toxicity limitation more stringent 
than 30,000 ppm (SPP) (for Option 2) and the high cost-effectiveness 
results for both Options 2 and 3, a preferred option has not been 
selected. EPA solicits comments on the appropriateness of each option.
    A large majority of operators are already discharging at levels 
less toxic than the toxicity limitations of 30,000 ppm (SPP) contained 
in Option 1. Thus, this is a no cost option incurring no economic or 
non-water quality environmental impacts.
    Option 2 requires zero discharge for all operators except in Cook 
Inlet where operators would be required to meet the Offshore 
subcategory limitations in addition to a toxicity limitation of between 
100,000 ppm (SPP) and 1,000,000 ppm (SPP). This option would cost $1.4 
million annually and results in less than a 0.1 percent reduction in 
estimated lifetime production for Cook Inlet platforms which would not 
significantly reduce the profit potential for these operators. Option 2 
would result in the removal of approximately 3.9 million pounds of 
pollutants being discharged per year (or 1264 pounds in toxic 
equivalents), assuming a volume of 17 percent of the discharges would 
not meet a toxicity limit of between 100,000 ppm and one million ppm 
(SPP) and would therefore be disposed of by grinding and injection or 
on land. Out of the 3.9 million pounds removed annually less than 0.02 
[[Page 9447]] percent consists of toxic priority pollutants (or 642 
pounds).
    Due to limitations with the data base, EPA is currently only able 
to estimate an achievable toxicity limit in the range of 100,000 ppm 
(SPP) to one million ppm (SPP). As described earlier under ``Additional 
Technologies Considered'' of this section, EPA is continuing to 
evaluate toxicity test results and volumes and other data for drilling 
fluids used and discharged in Cook Inlet in an effort to derive a more 
specific limitation. A supplemental notice presenting the data and 
soliciting comment would be necessary prior to promulgation.
    Option 3 would cost the industry $3.9 million annually and result 
in the reduction of 23 million pounds of pollutants being discharged 
per year (or 7375 in toxic pounds equivalents). Zero discharge of 
drilling fluids and drill cuttings is widely practiced in other coastal 
areas other than Cook Inlet, including the Gulf of Mexico, California, 
and the North Slope of Alaska. In Cook Inlet, zero discharge is not 
currently practiced but for a small amount of drilling fluids 
(approximately one percent) that do not meet permit limits. Zero 
discharge is technologically available because operators are able to 
comply with zero discharge by either disposing of their drilling fluids 
and drill cuttings onshore or by grinding and injecting the waste. The 
costs of this option would result in a 2.7 percent reduction in the 
estimated lifetime production for Cook Inlet platforms, which would not 
significantly reduce the profit potential for these operators. Thus, 
EPA believes these costs are economically achievable. However, concerns 
have been raised that zero discharge would interfere with drilling 
operations, in part because the weather conditions and tidal 
fluctuations in the Inlet pose logistical difficulties for drilling 
waste transportation especially during winter months. In addition, 
while Option 3 would result in the removal of 23 million pounds of 
pollutants per year, less than 0.02 percent of which are toxic 
pollutants, the $3.9 million annually incurred by industry to remove 
the 3760 pounds of priority toxic pollutants indicates that this option 
is not cost effective. (See EPA's cost effectiveness report entitled 
Cost Effectiveness Analysis of Effluent Limitations Guidelines and 
Standards for the Coastal Oil and Gas Industry in the rulemaking record 
for this proposal and additional discussion in Section VII of this 
preamble.) In Cook Inlet, operators are not currently practicing zero 
discharge. EPA estimates that to comply with a total zero discharge 
requirement, 24 percent of the drilling fluids and drill cuttings would 
be ground and injected into dedicated wells, and 76 percent would be 
disposed of onshore.
    EPA is soliciting comments on whether the drilling fluids and 
cuttings volumes removed by these options are deminimus, and on the 
effect that weather and transportation logistics, cost effectiveness, 
and other factors (e.g., types of fluids used and their composition, 
toxicity values, etc.) may have on the applicability, achievability and 
practicality of both Options 2 and 3.
    EPA does not expect any new source development wells drilled in 
Cook Inlet in the seven years following the scheduled promulgation of 
this rule. This is because all development wells are expected to be 
drilled from existing platforms in Cook Inlet. According to the 
definition of new sources, these wells would be existing sources. 
Additionally, any drillings that may occur in the recently discovered 
Sunfish formation in Upper Cook Inlet, are projected to be exploratory 
wells, which are also existing sources according to the new source 
definition. Thus, no costs will be attributed to NSPS in Cook Inlet 
because no new sources are projected for this area. However, in the 
case that a new source would be drilled in Cook Inlet, EPA has 
determined that zero discharge would not pose a significant barrier to 
entry for the drilling project. The same options are being considered 
for NSPS as for BAT, and again, no one preferred NSPS option is being 
selected in this proposal. Costs may be less than BAT because process 
modifications can be incorporated into the drilling rig design prior to 
its installation rather than retrofitting an existing operation. 
Whenever EPA determines that BAT is economically achievable, equivalent 
NSPS requirements would also be economically achievable, and cause no 
significant barrier to entry. EPA solicits comments on whether NSPS 
should be more stringent than BAT for Cook Inlet drilling fluids and 
cuttings.
    EPA also finds the non-water quality environmental impacts of 
Option 2 and zero discharge (Option 3) to be acceptable. Again, non-
water quality environmental impacts attributable to this rule would 
occur only in Cook Inlet. The air emissions and energy requirements 
associated with waste transportation were calculated for the two 
operators expected to utilize onshore landfill disposal to accommodate 
the wastes from their drilling operations. For the remaining two 
operators who will be drilling and do not have access to onshore 
disposal, EPA has calculated the air emissions and energy requirements 
resulting from grinding and injection to meet zero discharge. EPA has 
found that these non-water quality environmental impacts represent only 
a very small fraction of the total air emissions and energy 
requirements from normal operations, and that these non-water quality 
environmental impacts are acceptable. As stated above, EPA does not 
expect any new sources to be initiated in Cook Inlet. EPA, however, 
believes that the non-water quality environmental impacts resulting 
from any such activity would be equal to or less than those anticipated 
for existing sources, which EPA has found acceptable.
8. PSES and PSNS
    Section 307 of the CWA authorizes EPA to develop pretreatment 
standards for existing sources (PSES) and new sources (PSNS). 
Pretreatment standards are designed to prevent the discharge of 
pollutants that pass through, interfere with, or are otherwise 
incompatible with the operation of publicly owned treatment works 
(POTWs). The pretreatment standards for existing sources are to be 
technology based and analogous to the best available technology 
economically achievable (BAT) for direct dischargers. The pretreatment 
standards for new sources are to be technology-based and analogous to 
the best available demonstrated control technology used to determine 
NSPS for direct dischargers. New indirect discharging facilities, like 
new direct discharging facilities, have the opportunity to incorporate 
the best available demonstrated technologies, including process 
changes, and in-plant controls, and end-of-pipe treatment technologies. 
EPA determines which pollutants to regulate in PSES and PSNS on the 
basis of whether or not they pass through, interfere with, or are 
incompatible with the operation of POTWs.
    Based on the 1993 Coastal Oil and Gas Questionnaire and other 
information reviewed as part of this rulemaking, EPA has not identified 
any existing coastal oil and gas facilities which discharge drilling 
fluids and cuttings to publicly owned treatment works (POTW's), nor are 
any new facilities projected to direct these wastes in such manner. 
However, due to the high solids content of drilling fluids and 
cuttings, EPA is proposing to establish pretreatment standards for 
existing and new sources equal to zero discharge because these wastes 
are incompatible with POTW operations. For further 
[[Page 9448]] discussion, see the Coastal Technical Development 
Document. For PSNS, zero discharge would not cause a barrier to entry 
for the same reasons as discussed previously under Part 6.b. of this 
Section.

B. Produced Water

1. Waste Characterization
    Produced water is brought to the surface during the oil and gas 
extraction process and includes: formation water extracted along with 
oil and gas; injection water used for secondary oil recovery that has 
broken through the formation and mixed with the extracted hydrocarbons; 
and various well treatment chemicals added during the production and 
oil/water separation processes. Produced water is the highest volume 
waste in the coastal oil and gas industry. Depending on the age of a 
well and site-specific formation characteristics, the produced water 
can constitute between 2 percent and 98 percent of the gross fluid 
production at a particular well. Generally, in the early production 
phase of a well the produced water volume is relatively small and the 
hydrocarbon production makes up the bulk of the fluid. Over time, the 
formation approaches hydrocarbon depletion and the produced water 
volume usually exceeds the hydrocarbon production. Based on information 
received in the 1993 Coastal Oil and Gas Questionnaire, the average 
produced water rate from a well is approximately 1180 barrels per day 
(bpd) in Cook Inlet and 270 bpd in the Gulf coast. EPA estimates that 
228 million barrels per year (bpy) of produced water is discharged to 
surface waters by the coastal oil and gas industry.
    As part of this rulemaking, EPA has embarked upon a systematic 
effluent sampling program to identify and quantify the pollutants 
present in produced water, with an emphasis toward the identification 
of listed priority pollutants. Details of EPA's data collection 
activities are presented in Section V of this notice, with additional 
detail and sampling results discussed in the Coastal Technical 
Development Document. The information collected has confirmed the 
presence of a number of organic and metal priority pollutants in 
produced water.
    Pollutants contained in coastal oil and gas industry produced water 
discharges from facilities with treatment systems used to meet the BPT 
level permit limits were identified as part of EPA's sampling effort. A 
summary of the data from these sampling activities is contained in the 
Coastal Technical Development Document. EPA's sampling data and the 
industry-supplied Cook Inlet Study identified many organic priority 
pollutants and all of the 13 metal priority pollutants as being present 
in BPT treated produced water discharges following some treatment for 
oil and grease (oil) removal. The priority organics most often present 
in significant amounts were benzene, naphthalene, phenol, toluene, 2-
propanone, ethylbenzene and xylene. In addition to the priority 
pollutants, EPA identified total suspended solids, oil and grease, and 
a number of nonconventional pollutants including barium, chlorides, 
ammonia, magnesium, strontium and iron present in produced water.
2. Selection of Pollutant Parameters
    a. Pollutants Regulated.
    Where zero discharge would be required, all pollutants found in 
produced water discharges would be controlled. Where discharges would 
be allowed, i.e. Cook Inlet, EPA would be regulating oil and grease 
under BAT as an indicator pollutant controlling the discharge of toxic 
and nonconventional pollutants. Oil and grease would be limited under 
BCT as a conventional pollutant and under NSPS as both a conventional 
pollutant and as an indicator pollutant controlling the discharge of 
toxic and nonconventional pollutants.
    It has been shown previously in the development of the Offshore 
Guidelines (See the Offshore Technical Development Document, Section 
VI) that oil and grease serves as an indicator for toxic pollutants in 
the produced water wastestream, including phenol, naphthalene, 
ethylbenzene, and toluene. During its development of the Offshore 
Guidelines, EPA showed that gas flotation technology (the technology 
basis for the oil and grease limitations) removes both metals and 
organic compounds, resulting in lower concentration levels in the 
discharge for the above priority pollutants (See Section IX of the 
Offshore Technical Development Document).
    b. Pollutants Not Regulated.
    The feasibility of regulating separately each of the constituents 
of produced water determined to be present was also evaluated during 
the development of the Offshore Guidelines (See Section VI of the 
Offshore Technical Development Document). EPA determined that it is not 
feasible to regulate each pollutant individually for reasons that 
include the following: (1) The variable nature of the number of 
constituents in the produced water, (2) the impracticality of measuring 
a large number of analytes, many of them at or just above trace levels, 
(3) use of technologies for removal of oil which are effective in 
removing many of the specific pollutants, and (4) many of the organic 
pollutants are directly associated with oil and grease because they are 
constituents of oil, and thus, are directly controlled by the oil and 
grease limitation. These reasons also apply to the Coastal Guidelines.
    While the oil and grease limitations limit the discharge of toxic 
pollutants, EPA determined, during the Offshore Guidelines rulemaking, 
that certain of the toxic priority pollutants, such as 
pentachlorophenol, 1,1,-dichloroethane, and bis(2-chloroethyl) ether 
would not be controlled by the limitations on oil and grease in 
produced water. EPA is not proposing to regulate these pollutants in 
this rule because EPA did not detect them in the samples within the 
coastal oil and gas data base. (See the Coastal Technical Development 
Document).
3. Control and Treatment Technologies
    a. Current Practice.
    Based on information collected by the 1993 Coastal Oil and Gas 
Questionnaire as well as industry contacts, no coastal oil and gas 
facilities are discharging produced water in Alabama, Florida, 
California or Alaska's North Slope. This is due to a combination of 
factors including operational preference, waterflooding, and/or state 
requirements. In addition, the Louisiana Department of Environmental 
Quality issued regulations in 1992 (LAC:33,IX, 7.708) which prohibit 
discharges of produced water to fresh water areas characterized as 
``upland'' after July 1, 1992. The regulation defines ``upland'' as 
``any land not normally inundated with water and that would not, under 
normal circumstances, be characterized as swamp of fresh, intermediate, 
brackish or saline marsh''. The regulation does, however, allow 
discharges to the major deltaic passes of the Mississippi River and the 
Atchafalaya River. The same regulation also requires that discharges 
inland of the inner boundary of the Territorial Seas into intermediate, 
brackish or saline waters must either cease discharges or comply with a 
specific set of effluent limitations. These requirements must be met 
within a certain time frame, as required in the regulations, but, in 
most cases, no later than January 1997.
    In addition, EPA proposed general NPDES permits (57 FR 60926, 
December 22, 1992) for production wastes which would impose a 
prohibition on discharges of produced water in coastal 
[[Page 9449]] areas of Texas and Louisiana. These permits were 
finalized January 9, 1995 (60 FR 2387). The permits would not, however, 
apply to facilities treating offshore waters and discharging into the 
main passes of the Mississippi and Atachafalaya River. Based on these 
permits requiring zero discharge, only Alaska's Cook Inlet and two 
sites in the Gulf of Mexico would be discharging produced water in the 
Coastal subcategory at the time this final rule is scheduled to be 
signed, currently July 1996.
    The current BPT regulations established for the coastal subcategory 
limit the oil and grease content in the discharged produced water. 
Existing technologies for the removal of oil and grease include gravity 
separation, gas flotation, heat and/or chemical addition to assist oil-
water separation, and filtration. Methods for the discharge or disposal 
of produced water from facilities in the coastal subcategory include 
free fall discharge to surface waters, discharge below the water 
surface, use of channels to convey the discharge to water bodies, and 
injection via regulated Class II Underground Injection Control (UIC) 
wells into underground formations. As an alternative, a number of 
production sites transport produced water by pipeline, truck or barge 
to shore facilities for disposal in UIC Class II wells. At times, this 
transport consists of the gross fluid produced and the oil-water 
separation takes place at the off-site facility.
    While sampling data has indicated quantifiable reductions of 
naphthalene, lead, and ethylbenzene by BPT treatment (i.e., by oil-
water separation technology), this data also demonstrates the presence 
of significant levels of priority pollutants remaining in the treated 
effluent.
    b. Additional Technologies.
     In developing the proposed regulation, EPA evaluated several 
treatment technologies for application to the produced water 
wastestream. These technologies were considered for implementation at 
the coastal production sites and at the shore facilities where much of 
the produced water is currently treated for subsequent discharge to 
coastal subcategory waters.
     (1) Improved Gas Flotation.
     Gas flotation is a treatment process that separates low-density 
solids and/or liquid particles (e.g., oil and grease) from liquid 
(e.g., water) by introducing small gas (usually air) bubbles into 
wastewater. As minute gas bubbles are released into the wastewater, 
suspended solids or liquid particles are captured by these bubbles, 
causing them to rise to the surface where they are skimmed off.
     EPA considered as an option using gas flotation technology with 
chemical addition as a basis for improving 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 Technical Development Document Section IX).
    The addition of chemicals can be a particularly effective means of 
increasing the amount of pollutants removed. Because the performance of 
gas flotation is highly dependent on ``bubble-particle interaction,'' 
chemicals that enhance that interaction will increase pollutant 
removal.
    Gas flotation is a technology which has been used for many years in 
treating produced water in the offshore subcategory. In developing 
final effluent limitations guidelines and standards for the offshore 
subcategory (58 FR 12454; March 4, 1993), EPA evaluated comments and 
data submitted by the industry which strongly urged EPA to select 
improved gas flotation technology as the basis for BAT limits and NSPS, 
based on an Offshore Operator Committee's (OOC's) 83 Platform Composite 
Study. Industry further noted that chemical additives would improve the 
amount of oil and grease in produced water that could be removed. EPA 
thoroughly reviewed these comments and additional data, and agreed with 
industry that improved gas flotation should be used as the technology 
for setting BAT limits and NSPS in the offshore subcategory.
    In establishing BAT limits and NSPS for produced water, EPA 
evaluated the effluent data from the platforms in the 83 Platform 
Composite Study identified as using improved gas flotation (e.g., use 
of gravity separators and chemical additives). First, EPA modeled the 
offshore platform with ``median'' oil and grease effluent values (i.e., 
50 percent of the platforms in the database had oil and grease effluent 
values above (and 50 percent below) the median of the effluent values 
measured at the median platform. Based on the oil and grease measured 
at the median platform after improved gas flotation treatment, and 
allowing for average ``within-platform'' variability, EPA set a daily 
maximum limit on oil and grease at 42 mg/l, and a 30-day average of 29 
mg/l as the BAT limits and NSPS. (See 58 FR 12462, March 4, 1993).
    In setting BAT limits and NSPS for the offshore rule, EPA had a 
choice among several different means of measuring what is termed ``oil 
and grease'' in produced water, two of which are known as Method 413.1 
and Method 503E.
    Under Method 413.1, freon is mixed with a sample of produced water. 
The container is then left at rest to separate the water phase from the 
freon phase, which includes those contaminants in produced water that 
dissolve in freon. The freon layer is then drained from the container 
and distilled by heating, leaving a residue. The residue is then 
weighed and reported as the weight of the ``oil and grease'' in that 
sample of produced water. The results are typically reported in 
milligrams of oil and grease per liter of produced water.
     Under Method 503E the same steps are followed, with one exception. 
After the freon layer is drained from the container, but prior to 
distillation, silica gel is added to the freon, and weighed. Because 
the silica gel has the ability to adsorb polar materials (e.g., some of 
the hydrocarbons and fatty acids present) that otherwise would have 
been measured as oil and grease in the freon residue by Method 413.1, 
the analytical result reported under Method 503E is less than that 
reported under Method 413.1. Because Method 413.1 measures more of the 
oil and grease in produced water, it gives a more complete picture of 
the efficiency of the treatment system. Because EPA had influent and 
effluent data showing that oil and grease, measured under Method 413.1, 
were removed by the use of improved gas flotation (Oil Content in 
Produced Brine on Ten Louisiana Production Platforms, September 1981) 
R.I.G. (No. 194), EPA used improved gas flotation as the technology 
basis for the rule and established the limitations as measured by 
Method 413.1 (See also Final Report, Analysis of Oil and Grease Data 
Associated with Treatment of Produced Water by Gas Flotation 
Technology, January 13, 1993, and 58 FR 12462, March 4, 1993).
     (2) Filtration.
     The primary purpose of filtration is to remove suspended matter, 
including [[Page 9450]] insoluble oils, from produced water. Additional 
removal of soluble pollutants can also be achieved, but it is not as 
significant as the reduction of conventional pollutants such as total 
suspended solids and oil and grease. EPA has considered several types 
of filtration systems as part of this rulemaking, including granular, 
membrane and cartridge filtration technologies. EPA's assessment of 
granular filtration is based in part on data collected from a coastal 
oil and gas facility as part of the offshore subcategory rulemaking 
(Three Facility Study). Although economically achievable, granular 
filtration was rejected as the technology basis for controlling 
discharges in this proposed rule. EPA's evaluation of granular 
filtration performance data indicates that while this technology does 
provide some removals of priority and nonconventional pollutants, the 
pollutant removal efficiency of granular filtration (in the range of 
46-68 percent oil and grease removal) is generally not as effective as 
that attainable through improved operation of gas flotation technology 
(general oil and grease removal efficiency have been shown to be 90-95 
percent). In addition, the capital and annual operating and maintenance 
costs associated with granular filtration are significantly higher than 
the costs of improving gas flotation systems.
     EPA did not select membrane filtration as a technology basis for 
this proposed rule because it has not been sufficiently demonstrated as 
available to support national effluent limitations at this time. 
Membrane filtration is a commercially demonstrated technology in other 
industries and several manufacturers have been developing this 
technology for use in treating produced water. Although not yet 
available to the oil and gas industry, some operators have shown 
interest in the technology and limited testing of these systems has 
taken place. In developing the final limitations for the offshore 
subcategory, EPA determined that because of operational problems (e.g., 
fouling of the membrane, actual treatment capacity less than design 
capacity) this technology did not support use as a technology basis for 
final effluent limitations. (See 58 FR 12481; March 4, 1993.) In the 
absence of any data to the contrary, EPA believes that this technology 
still is not available for full-scale systems capable of long-term, 
effective treatment of produced water.
    In evaluating reinjection of produced water, EPA noted that a 
number of coastal oil and gas sites were using cartridge filters as 
part of the treatment system. EPA collected wastewater samples to 
characterize the efficacy of cartridge filtration to determine whether 
this technology should serve as a basis for effluent limitations and 
standards. EPA's evaluation of cartridge filtration performance data 
indicates that this technology is capable of providing oil and grease 
removal only marginally better than that currently required by the 
existing BPT effluent limitations. In addition, EPA's evaluation did 
not identify any significant removals of the priority and 
nonconventional pollutants present in produced water. Thus, cartridge 
filtration was not selected as a basis for limiting produced water 
discharges.
3. Injection
     EPA also considered using injection technology as a basis for 
setting a more stringent requirement under this rule. With the 
exception of Cook Inlet, injection of produced water is widely 
practiced by facilities in the coastal subcategory as well as in the 
onshore subcategory. Injection technology for produced water consists 
of injecting it, under pressure, into Class II UIC wells into 
underground formations. This option results in no discharge of produced 
water to surface waters.
     Treatment of the produced water prior to injection is usually 
necessary, and such treatment often includes removal of oil and 
suspended matter by BPT oil separation technology followed by 
filtration technology. The removal of suspended matter prior to 
injection is required to prevent pressure build-up and plugging of the 
receiving formation and/or to protect injection pumps from damage.
     While EPA determined that filtration was not a technology 
appropriate for serving as the basis for control of effluent prior to 
discharge, filtration was considered relevant technology for use as 
pretreatment prior to injection, thus, it is included as part of the 
basis for the injection technology option. EPA determined from 
information gathered on site visits in the Gulf coast area, as well as 
from industry contacts, that cartridge filtration is generally used 
following BPT oil/water separation technologies at injecting facilities 
accessible by water only. For facilities accessible by land, it was 
determined that rather than pretreat produced water using filtration, 
it is more cost effective to perform periodic well workovers on the 
injection well to remove clogged material from the wellbore. However, 
for facilities treating produced water flows greater than 64,000 bpd, 
EPA determined that it would be more appropriate to employ granular 
filtration after BPT separation technology because it is more cost 
effective to use this technology for higher flows rather than cartridge 
filtration.
 4. Other Technologies
    In developing effluent limitations for the offshore subcategory, 
EPA also considered other technologies such as carbon adsorption, 
biological treatment, chemical precipitation, and hydrocyclones. (See 
56 FR 10688; March 13, 1991.) Carbon adsorption was rejected as a 
technology basis because the limited use of this technology did not 
give sufficient performance data to enable a full evaluation. 
Biological treatment was rejected because of problems associated with 
biologically treating the high dissolved solids (brine) waters. 
Operational problems and an inability to quantify reductions of 
priority pollutant metals led to rejection of chemical precipitation. 
Hydrocyclones were rejected as a technology basis for BAT/NSPS effluent 
limits because the performance data available demonstrated only that it 
was capable of meeting existing BPT limits for oil and grease, and data 
were lacking regarding removals of priority pollutants. EPA has not 
received any new information regarding treatment efficacy (as measured 
by priority pollutant removal) for these technologies, and is not aware 
of any information which would support conclusions different than those 
made for the Offshore Guidelines.
5. Options Considered
    Five options were considered by EPA in developing BCT, BAT, NSPS, 
PSES and PSNS limitations for produced water. These options were based 
on either injection, improved gas flotation, or a combination of these 
technologies. The 5 options are listed below with limitations for oil 
and grease associated with the options allowing discharges:
    Option 1--(BPT All): EPA has included as an option setting effluent 
limitations equal to the existing BPT requirements. Oil and grease 
would be limited in the effluent at 48 mg/l monthly average, and 72 mg/
l daily maximum.
    Option 2--(Improved Flotation All): All discharges of produced 
water would be required to meet limitations on oil and grease content 
of 29 mg/l 30-day average and a daily maximum of 42 mg/l. The 
technology basis for these limits is improved operating performance of 
gas flotation. The specific numerical limit of 29 mg/l 30-day average 
and 42 mg/l (daily maximum) are based on the statistical analyses of 
performance of [[Page 9451]] improved gas flotation conducted to 
develop oil and grease limits for the Offshore Guidelines. (See 58 FR 
12462, March 4, 1993).
    Option 3--(Zero Discharge; Cook Inlet BPT): With the exception of 
facilities in Cook Inlet, all coastal oil and gas facilities would be 
prohibited from discharging produced water. Coastal facilities in Cook 
Inlet would be required to comply with existing BPT effluent 
limitations (48/72 mg/l described above) for oil and grease.
    Option 4--(Zero Discharge; Cook Inlet Improved Flotation): With the 
exception of facilities in Cook Inlet, all coastal oil and gas 
facilities would be prohibited from discharging produced water. Coastal 
facilities in Cook Inlet would be required to comply with the oil and 
grease limitations of 29 mg/l 30-day average and 42 mg/l daily maximum 
based on improved operating performance of gas flotation and the 
statistical analysis conducted for the Offshore Guidelines.
    Option 5--(Zero Discharge All): This option would prohibit all 
discharges of produced water based using injection.
    Specific alternatives have been developed for Cook Inlet to account 
for the different operational practices, and geological situations that 
exist at these platforms. As previously stated, zero discharge is 
widely, if not exclusively, practiced in all coastal areas except Cook 
Inlet. Injection of produced waters is not practiced in Cook Inlet 
because, where waterflooding is occurring, treated seawater is injected 
instead. Industry claims that injection of seawater other than produced 
water for enhanced recovery is practiced primarily because injection of 
produced water would cause formation fouling. Industry has claimed that 
fouling would occur due to bacteria and scale formation in produced 
water, and otherwise not present in seawater. EPA has determined that 
formation fouling problems associated with produced water injection are 
not insurmountable because filtration and anti-fouling chemicals can be 
added prior to injection, and periodic downhole workovers can be 
performed to reopen clogged formation surfaces.
    An additional problem with injecting produced waters is that no 
other formations exist that can accommodate this wastestream other than 
the producing formation. Cook Inlet operators would experience 
significant additional cost associated with piping produced water if 
zero discharge was required from where it is currently treated to where 
it could be injected. Of the 13 producing platforms in the Inlet, 9 of 
them currently direct their extracted hydrocarbon fluids to one of 3 
land-based separation and treatment facilities. These land-based 
facilities separate the hydrocarbons from the produced water, treat the 
produced water and then discharge it in accordance with EPA's Region 
X's NPDES general permit requirements. The Alaska Oil and Gas 
Conservation Commission has confirmed that no geological formations 
exist beneath the land-based facilities that are large enough to accept 
the approximately 100,000 barrels per day (bpd) of produced water 
generated from these facilities. Thus, produced water would be piped 
back to the platforms for injection if produced water discharges were 
prohibited. The costs for such piping would comprise 74 percent of the 
total costs for injection. This would be a major cost factor for the 
Inlet operations overall since the volume of produced water being 
discharged from these 3 land-based facilities amounts to approximately 
99 percent of that discharged from all 13 platforms.
6. BCT Options
    a. BCT Methodology.
    The methodology to determine the appropriate technology option for 
BCT limitations is previously described in Section VI.A.
    b. BCT Cost Test Calculations and Option Selection.
    The five options previously described, were evaluated according to 
the BCT cost reasonableness tests. The pollutant parameters used in 
this analysis were total suspended solids and oil and grease. All 
options, except the ``BPT All'' option, fail the BCT cost 
reasonableness test and thus, EPA proposes to establish BCT limitations 
equal to BPT. Costs for the ``BPT All'' option are equal to zero 
because facilities are complying with the current BPT limitations. The 
range of the results for the POTW test (first part of the BCT cost 
test) for the other options is $1.35 to $3.70 per pound of conventional 
pollutant removed. Since a value of less than $0.53 per pound (1992$) 
is required to pass the POTW test these four options fail the first BCT 
cost test. Thus, EPA is proposing to establish the BCT limitations for 
produced water equal to BPT (48 mg/l monthly average; 72 mg/l daily 
maximum). The calculations for BCT cost reasonableness test for the 
produced water options are described in more detail in Section XI of 
the Coastal Technical Development Document. There are no incremental 
non-water quality environmental impacts associated with the BCT option 
because it is equal to BPT.
7. BAT and NSPS Options
    EPA has selected Zero discharge; Cook Inlet improved gas flotation 
(Option 4) for the BAT and NSPS level of control for produced water. A 
discussion of the cost and impacts and a description of the selection 
rationale is contained below:
    a. Costs.
    The cost and pollutant removals associated with the options 
considered for BAT are presented in Table 5.

  Table 5.--Costs and Pollutant Removals for Produced Water BAT Options 
------------------------------------------------------------------------
                                                              Pollutant 
                                                   Costs       removals 
                    Option                        (1992$)       (lbs)   
                                                  (x1000)      (x1000)  
------------------------------------------------------------------------
1. BPT all....................................            0            0
2. Improved gas flotation all.................       12,400       12,440
3. Zero discharge; cook inlet BPT.............       28,600    4,306,800
4. Zero discharge; cook inlet improved gas                              
 flotation....................................       30,860    4,308,300
5. Zero discharge all.........................       49,700    5,484,800
------------------------------------------------------------------------

    These estimates are presented incremental to the baseline of 
current industry operating practices which is equal to BPT where 
discharges are occurring. Thus, as shown on Table 5, costs attributable 
to Option 1, which is equal to BPT, is zero. On January 9, 1995 (60 FR 
2387), EPA promulgated general NPDES permits that would prohibit 
discharges of produced water from coastal facilities in Texas and 
Louisiana. For the purpose of this proposal, EPA's compliance cost 
estimates and economic impact assessments are determined without 
considering this permit. Had EPA's costing estimates assumed that the 
general permit would be in effect, the total estimated cost of the 
proposed BAT limitations for produced water for the entire coastal 
subcategory would be $10.4 million instead of $30.9 million annually.
    In developing the costs of zero discharge for this option, EPA 
determined, based on Texas and Louisiana state permit data, the number 
and volume of produced water discharges that would be discharging by 
the time this final rule is scheduled to be signed July 1996. This 
investigation identified, by operator and oil and gas field, 216 
produced water separation/treatment facilities that would be 
discharging approximately 180 million barrels per year (bpy) in Texas 
and [[Page 9452]] Louisiana as of July 1996. Costs are calculated 
without taking into account the regulatory effects of the zero 
discharge requirement imposed by the EPA Region VI General Permits (See 
Section II.C. of this preamble).
    In determining the costs associated with zero discharge for the 
Gulf coast area, EPA utilized the following factors in the costing 
analyses:

General

    * The only areas that will incur compliance costs are Cook Inlet in 
Alaska, Texas, and parts of Louisiana since all other coastal areas 
that have oil and gas activities currently practice zero discharge.

For Texas and Louisiana

    * Produced water would be injected into Class II UIC injection 
wells. The capacity of each Class II injection well is 5,000 BPD.
    * 90 percent of the injection wells would be converted from 
previously producing wells or dry holes.
    * If a discharge is greater than 108 bpd (for water-based 
facilities) and 71 bpd (for land-based facilities), then the produced 
water would be injected onsite; if the discharge is less than those 
flows then it would be more cost effective to send the produced water 
offsite to a commercial facility for injection. (EPA's data from Texas 
and Louisiana coastal permits show that 77 percent of the produced 
water discharges would inject on-site).
    * For purposes of estimation, all Texas separation/treatment 
facilities are located on land and all Louisiana separation/treatment 
facilities are located over water. EPA is aware that this is not 
entirely the case, i.e. some facilities in Louisiana are located over 
land and some Texas facilities are located over water. In the absence 
of specific location information on all of the 216 discharging 
facilities, EPA determined this to be a good approximation since the 
coastal topography of Louisiana consists of more extensive wetlands 
than that of Texas. (Location is an important factor when determining 
the cost of drilling an injection well, and the cost of produced water 
transportation. EPA's state permit data base shows that 24 percent of 
the produced water discharges are in Texas and the separation/treatment 
facilities are therefore considered to be on land).
    * No pretreatment beyond BPT technology is required prior to 
injection for land-based facilities because it is more cost effective 
to perform downhole well workovers twice a year. Pretreatment beyond 
BPT treatment prior to injection consists of cartridge filtration for 
water-based facilities. For flows greater than 64,000 bpd, granular 
filtration is used as pretreatment.
    * Capital costs are based on sizing equipment to accommodate future 
produced water volume, estimated to be approximately 1.5 times current 
flow.
    * Where more than one produced water discharge location exists from 
one or more production facilities owned by the same operator in the 
same field, EPA combined the discharges to be injected into a single 
injection system. By combining discharges a savings would result due to 
installation of fewer injection wells.
    For Cook Inlet
    * No geological formations are available for produced water 
injection except the producing formations.
    * No geological formations are available near or below the existing 
onland separation/treatment facilities. Thus, the produced waters would 
be required to be piped back to the platforms for injection.
    * Pretreatment prior to injection consists of gas flotation and 
multimedia filtration. However, operators will use existing equipment 
where it currently exists, and no costs would be incurred for such 
existing equipment.
    * During the development of this proposal, industry provided EPA 
with information on reservoir plugging and souring that may result from 
injecting produced water in the Cook Inlet. EPA, in its cost analysis, 
included costs for the addition of chemicals that would be added to the 
produced water being injected to alleviate the scaling and hydrogen 
sulfide (H2S) formation problems associated with injection in this 
area. Such chemicals include biocides and scale inhibitors. Annual 
workovers must also be performed on the injection wells.
    EPA believes that the cost estimates are conservative for a number 
of reasons. As discussed previously, EPA determined costs to comply 
with a zero discharge requirement in the Gulf of Mexico based on the 
number of facilities that would be discharging after the expected date 
of promulgation for this rule (July 1996). A total of 216 facilities 
would still be discharging by then. However, 28 of these facilities in 
Louisiana will be required to cease discharging by January 1, 1997, 
because of the state water quality standard's no discharge requirement. 
Taking this January 1997 requirement into account as a portion of the 
baseline would further reduce costs by 25 percent.
    Furthermore, EPA's cost estimates for zero discharge in the Gulf of 
Mexico are based on sizing produced water treatment equipment to 
accommodate future produced water volumes estimated to be approximately 
1.5 times current flow. EPA believes using this factor, which is 
standard engineering practice, has resulted in a conservative cost 
estimate overall because many operators have indicated that they 
typically use a factor of 1.2 to 1.25 when sizing and costing produced 
water treatment equipment. Capital costs would be approximately 12 
percent lower if a factor of 1.2 were used. Additionally, while EPA's 
costing included combining of operator discharges for injection within 
fields, the analysis showed that costs are not significantly different 
if they are not combined. This is because the high costs of piping to 
join discharges closely equal the costs of individual injection well 
installation.
    EPA also calculated capital costs of produced water treatment on 
the basis that produced water flows increase the same for oil as for 
gas wells. While produced water volumes from gas producing wells will 
generally not increase at the rate of 1.5, EPA did not differentiate 
between the two.
    EPA determined that no costs would be attributed to zero discharge 
for California, Florida, Alabama, certain parts of Louisiana, and the 
North Slope of Alaska because operators in these areas are already 
practicing zero discharge of all produced waters.
    For improved gas flotation, costs were estimated based on an 
evaluation of this technology during development of the Offshore 
Guidelines (58 FR 12463). Improved performance of gas flotation units 
includes improved operation and maintenance of gas flotation treatment 
systems and chemical pretreatment to enhance system effectiveness. 
Costs are based on vendor-supplied data, industry information, cost 
analyses conducted by the Department of Energy, and EPA projections. 
Capital and O & M costs were applied specifically to the coastal oil 
and gas operations using nine modeled flows for land- and water-access 
production facilities. From these nine modeled flows, EPA conducted 
regression analyses to derive cost equations that would vary based on 
flow. These equations were then applied to the actual 216 discharging 
facilities to estimate costs on a site specific basis. Capital costs 
include equipment purchase, installation, and platform or concrete pad 
(for land based operations) retrofit. Operation and maintenance costs 
are estimated to be 10 percent of capital costs.
    EPA solicits comments on these costs and also information regarding 
the longitude and latitude locations of [[Page 9453]] discharging 
produced water separation/treatment facilities in Texas.
    The total annual cost of Option 4 for BAT control of produced water 
discharges from existing facilities is estimated at $30.9 million (1992 
dollars) for the entire coastal subcategory. $29.2 million of this 
total would be incurred by operators in the Gulf Coast states of TX and 
LA in attaining zero discharge. The remaining $2.3 million would be 
incurred by Cook Inlet operators in complying with the oil and grease 
limitations. EPA finds this cost to be economically achievable for the 
reasons discussed later in Section VII of this preamble but are briefly 
summarized here. Total production losses realized from this option are 
expected to total 15.2 million bbls over the lifetime of the wells and 
platforms subject to this rule which equals up to 1.7 percent of total 
lifetime production for the Gulf and Cook Inlet combined. The net 
present value losses of producer income associated with this decrease 
in production is $153.2 million. A total of 111 wells in the Gulf coast 
area (2.4 percent of all current Gulf coast wells) and no Cook Inlet 
platforms are considered likely to shut in immediately when this 
proposal becomes final. Furthermore, a maximum of 12 Gulf operators 
might fail as a result of this BAT option (2.8 percent of the current 
Gulf operators). No company failures are expected in Cook Inlet. This 
option would reduce the pollutant loading from this wastestream by 4.3 
billion pounds per year.
    c. Rationale for Selection of BAT.
    EPA proposes Zero Discharge; Cook Inlet Improved Gas Flotation 
Option 4: as BAT for produced water. This option prohibits discharges 
of produced water from all coastal facilities, except for those 
facilities located in Cook Inlet. Coastal facilities in Cook Inlet 
would be required to comply with the oil and grease limitations (29 mg/
l 30-day average, 42 mg/l daily maximum) based on improved operating 
performance of gas flotation. EPA has determined this option to be 
economically achievable and technologically available, and that it 
reflects the BAT level of control.
    Zero discharge is technologically available because injection of 
produced water is currently ongoing in much of the coastal subcategory 
at the present time and adequate geological formations exist to accept 
produced water. By 1996, 72 percent of the facilities in the Gulf 
region will be meeting zero discharge. The oil and grease limit 
applicable to Cook Inlet is technologically available for the reasons 
discussed elsewhere in this preamble, the record for this rule, as well 
as in cited portions of the rulemaking record for the Offshore 
Guidelines.
    Option 4 is economically achievable because, as the economic 
analysis shows (in Section VII), total production losses in terms of 
oil production as a result of this proposed rule are expected to range 
between 1.0 percent and 1.7 percent of total lifetime production for 
both Cook Inlet and the Gulf. Additionally, only 2.4 percent of all 
current Gulf coastal wells (111 out of 4675 current Gulf coastal wells) 
and no Cook Inlet platforms are considered likely to shut in as a 
result of this rule. These shut-in wells tend to be relatively low-
producing and marginal wells. At most, only 2.8 percent of the 
operators in the Gulf (12 of the estimated 435 Gulf coastal operators) 
might fail as a result of a zero discharge requirement and no firm 
failure is expected in Cook Inlet, as a result of meeting oil and 
grease limits of 29 mg/l 30-day average and 42 mg/l daily maximum for 
produced water. (The range of firm failures in the Gulf is actually 0-
12, but because data were not available to rule out the possibility of 
failures, EPA assumed possible failures to be actual failures.) The 
``average'' Gulf coastal firm does not discharge produced water and 
coastal firms are expected to face average (medium) declines in equity 
or working capital of 0 percent. Of the 122 discharging firms, average 
(medium) declines in equity or working capital of 0.37 percent and 2.63 
percent, respectively, are expected to occur. These impacts, combined 
with the fact that most Gulf coastal operators (72 percent) will not be 
discharging by 1996, show Option 4 to be economically achievable.
    Option 5, zero discharge all was not selected based on the 
unacceptable economic impacts estimated for the Cook Inlet operators. 
EPA's economic analysis shows that 3 of 13 platforms would be ``shut-
in'' or closed down and believes that this economic impact is 
unacceptable in Cook Inlet. EPA did not select the ``Flotation All'' or 
``BPT All'' options as preferred because they, applied industry-wide, 
do not represent BAT or NSPS level of control. As stated previously, 
all coastal operations in California, Alabama, Florida, some parts of 
Louisiana and the North Slope of Alaska do not discharge produced 
water, but inject their produced water underground either to comply 
with permit limitations or to enhance hydrocarbon recovery. EPA has 
therefore concluded that control options based on the continued 
discharge of produced water in all areas of the country do not 
represent BAT or NSPS. Non-water quality environmental impacts for the 
proposed Option 4 consist of incremental air emissions of approximately 
2800 tons/year across the entire subcategory. Given that an average 
Gulf coast production facility may alone produce approximately 188 
tons/year of emissions, this option would increase air emissions by 
about 13 percent. EPA considers this increase to be acceptable. A 
description of estimated non-water quality impacts, consisting of 
additional energy requirement and air emission created by complying 
with the proposed requirements and other options being considered are 
discussed in Section VIII of this preamble and in more detail in 
Chapter XIV of the Coastal Technical Development Document.
    d. Rationale for Selection of NSPS.
    For NSPS control of produced water discharges from new sources, EPA 
is proposing the ``Zero Discharge All'' (Option 5) prohibiting 
discharges of produced water from all new sources. Option 5 is 
economically achievable for the reasons discussed in the economic 
impact analysis and in Section VII, below. This NSPS option is 
estimated to cost approximately $4.5 million annually for the entire 
coastal subcategory. This cost would be incurred only by Gulf Coast 
operators where EPA estimates that approximately 6 new production 
facilities will be constructed per year. No new sources are expected in 
the Cook Inlet (See Section VII). However, were new sources to be 
installed in Cook Inlet, the preferred NSPS option of zero discharge is 
not expected to cause a barrier to entry because new project operations 
would still be quite profitable. For a new source, EPA estimates that 
the decline in internal rates of return would only be reduced from 39 
to 37 percent and therefore would not be likely to affect the decision 
to undertake a new project. In addition, the impact on Net Present 
Value from the zero discharge requirement (2.9 percent) is not 
substantially different from the impacts on Net Present Value from the 
proposed BAT option for Cook Inlet platforms (2.4 percent). Thus 
existing and new platforms would face similar impacts on Net Present 
Value and Internal Rate of Return. In addition, as discussed in Section 
VIII, EPA has determined the non-water quality environmental impacts to 
be acceptable for the NSPS option for produced water. Total incremental 
emissions from the proposed option is approximately 64 tons/year for 
NSPS. As a comparison, an average Gulf coast production facility may 
produce approximately 188 tons/year of emissions. EPA considers this 
[[Page 9454]] increase in non-water quality impacts to be acceptable.
8. PSES and PSNS Options Selection
    Based on the 1993 Coastal Survey and other information reviewed as 
part of this rulemaking, EPA has not identified any existing coastal 
oil and gas facilities which discharge produced water to publicly owned 
treatment works (POTWs), nor are any new facilities projected to direct 
their produced water discharge in such manner. However, because EPA is 
proposing a limitation requiring zero discharge for those existing 
facilities, there is the potential that some facilities may consider 
discharging to POTWs in order to avoid the BAT and /or NSPS 
limitations. Pretreatment standards for produced water are appropriate 
because EPA has identified the presence of a number of toxic and 
nonconventional pollutants, many of which are incompatible with the 
biological removal processes at POTWs. Large concentrations of 
dissolved solids in the form of various salts in the produced water 
cause the discharge to POTWs to be incompatible with the biological 
treatment processes because these ``brines'' can be lethal to the 
organisms present in the POTW biological treatment systems. (See the 
Coastal Technical Development Document for detailed information on 
produced water characterization.) EPA does not have sufficient data for 
conducting a pass through analysis for reasons discussed further in the 
Coastal Technical Development Document. EPA solicits data and comment 
on this particular issue.
    EPA is proposing to require pretreatment standards for existing and 
new sources (PSES and PSNS, respectively) that would prohibit the 
discharge of produced water. The technology basis for compliance with 
PSES and PSNS would be the same as that for BAT and NSPS zero discharge 
limits. The cost projections for both PSES and PSNS are considered to 
be zero since no existing sources discharge to POTW's and there are no 
known plans for new sources to be installed in locations amenable to 
sewer hookup. Also, because no facilities are discharging to POTW's EPA 
proposes that PSES and PSNS requiring zero discharge be effective as of 
the effective date of this rule. Because zero discharge for new sources 
is economically achievable, the costs of complying with zero discharge 
would not be a barrier to entry. Non-water quality environmental 
impacts would be similar to those for new sources, which EPA has found 
to be acceptable. Thus, EPA has determined that pretreatment standards 
for new sources that are equal to NSPS are economically achievable and 
technologically available for PSNS and that the non-water quality 
environmental impacts are acceptable.

C. Produced Sand
1. Waste Characterization
    Produced sand consists primarily of the slurried particles that 
surface from hydraulic fracturing and the accumulated formation sands 
and other particles (including scale) generated during production. 
Produced sand is generated during oil and gas production by the 
movement of sand particles in producing reservoirs into the wellbore. 
The generation of produced sand usually occurs in reservoirs comprised 
of geologically young, unconsolidated sand formations. The produced 
sand wastestream is considered a solid and consists primarily of sand 
and clay with varying amounts of mineral scale and corrosion products. 
This waste stream may also include sludges generated in the produced 
water treatment system, such as tank bottoms from oil/water separators 
and solids removed in filtration.
    Produced sand is carried from the reservoir to the surface by the 
fluids produced from the well. The well fluids stream consists of 
hydrocarbons (oil or gas), water, and sand. At the surface, the 
production fluids are processed to segregate the specific components. 
The produced sand drops out of the fluids stream during the separation 
process and accumulates at low points in equipment. Produced sand is 
removed primarily during tank cleanouts. Because of its association 
with the hydrocarbon stream during extraction, produced sand is 
generally contaminated with crude oil or gas condensate.
    Produced sand samples were obtained during EPA's sampling visits to 
10 production facilities. Analysis of these samples showed oil and 
grease concentrations of 205 g/Kg. All toxic metals were present except 
silver, with most notable contributions from copper (32.15 mg/Kg) and 
lead (171.94 mg/Kg). Naturally Occurring Radioactive Material (NORM) 
was present at an average of 8.9 pCi/g in the samples which were taken 
from coastal facilities in the Gulf of Mexico. Toxic organics present 
were similar to those found in produced water including benzene, 
ethylbenzene, xylene, toluene, propanone and phenanthrene. All 10 sites 
disposed of the produced sands at commercial facilities. Produced sand 
volumes vary from well to well and are a function of produced water 
production, formation type, and well completion methods. Maximum 
produced sand volumes (out of these 10 sites) was 400 bpy per 
production facility. The 1993 Coastal Survey results showed that 
average volumes of produced sand ranged from 36 to 94 bpy per facility. 
Additional discussion of produced sand is presented in the Coastal 
Technical Development Document.
2. Selection of Pollutant Parameters
    EPA is proposing to control all pollutants present in produced sand 
by prohibiting discharge of this wastestream.
3. Control and Treatment Technologies
    No effluent limitations guidelines have been promulgated for 
discharges of produced sand in the coastal subcategory. The final NPDES 
permits for Texas, Louisiana, and the existing state NPDES permits for 
Alabama contain a zero discharge limit for produced sand.
    Data from the 1993 Coastal Oil and Gas Questionnaire indicate that 
the predominant disposal method for produced sand is landfarming, with 
underground injection, landfilling, and onsite storage also taking 
place to some degree. Because of the cost of sand cleaning, in 
conjunction with the difficulties associated with cleaning some sand 
sufficiently to meet existing permit discharge limitations, operators 
use onshore (onsite or offsite) or downhole disposal. In fact, only one 
operator was identified in the 1993 Coastal Oil and Gas Questionnaire 
as discharging produced sand in the Gulf of Mexico, but this operator 
also stated that it planned to cease its discharge in the near future. 
All Cook Inlet operators submitted information stating that no produced 
sand discharges are occurring in this area.
4. Options Considered and Rationale for Options Selection
    The only option considered is zero discharge of produced sands. 
Because current industrial practice for the coastal subcategory is 
predominately zero discharge, EPA considered this the appropriate 
option for this wastestream. The zero discharge requirement would 
eliminate the discharge of toxic pollutants present in produced sand. 
Because the industry practice of zero discharge is already so 
widespread, the zero discharge limitation will result in minimal 
increased cost to the industry.
    EPA is proposing to set BPT, BCT, BAT and NSPS equal to zero 
discharge for produced sand. EPA has determined that zero discharge 
reflects the BPT, [[Page 9455]] BCT, BAT and NSPS levels of control 
because, as it is widely practiced throughout the industry, it is both 
economically achievable and technologically available. Zero discharge 
for NSPS would not cause a barrier to entry because, since it is equal 
to current practice, it will impose no cost. Zero discharge will have 
negligible economic impacts on the industry. As zero discharge reflects 
current practice, there are negligible incremental non-water quality 
environmental impacts from this option. Since proposed BCT would be set 
equal to the proposed BPT, there is no cost of BCT incremental to BPT. 
Therefore, this option passes the BCT cost reasonableness tests.
    The technology basis for compliance with PSES and PSNS is the same 
as that for BAT and NSPS. EPA proposes pretreatment standards for 
produced sands equal to zero discharge because, like drilling fluids 
and cuttings, their high solids content would interfere with POTW 
operations. Because EPA is not aware of any produced sands being sent 
to POTWs, this requirement is not expected to result in operators 
incurring costs. Zero discharge for PSNS would not cause a barrier to 
entry for the same reasons as discussed above for NSPS. There are no 
additional non-water quality environmental impacts associated with this 
requirement because it reflects current practice.

D. Deck Drainage

1. Waste Characterization
    Deck drainage consists of contaminated site and equipment runoff 
due to storm events and wastewater resulting from spills, drip pans, or 
washdown/cleaning operations, including washwater used to clean working 
areas. Deck drainage is generated during both the drilling and 
production phases of oil and gas operations. Currently, approximately 
11.5 million bpy of deck drainage are discharged by facilities in the 
coastal subcategory. EPA estimates that 112,000 pounds of oil and 
grease are discharged in this wastestream annually. In addition to oil, 
various other chemicals used in drilling and production (actual 
hydrocarbon extraction) operations may be present in deck drainage. 
Limited treated effluent data are available for this wastestream, 
however, EPA has identified the presence of organic and metal priority 
pollutants in deck drainage. EPA's analytical data for deck drainage 
comes from the data acquired during the development of the Offshore 
Guidelines. EPA conducted a three facility sampling program (described 
in Section V of the Offshore Technical Development Document) during 
which samples were taken of untreated deck drainage. Eight of the toxic 
metals were detected, most notably lead (ranging in concentration from 
25 - 352 ug/l) and zinc (ranging in concentration from 2970-6980 ug/l). 
Priority organics were also present including benzene, xylene, 
naphthalene and toluene. Other nonconventional pollutants found in deck 
drainage include aluminum, barium, iron, manganese, magnesium and 
titanium.
    The content and concentrations of pollutants in deck drainage can 
also depend on chemicals used and stored at the oil and gas facility. 
An additional study on deck drainage from Cook Inlet platforms, 
reviewed during development of the Offshore Guidelines, showed that 
discharges from this wastestream may also include paraffins, sodium 
hydroxide, ethylene glycol, methanol and isopropyl alcohol. (Dalton, 
Dalton, and Newport, Assessment of Environmental Fate and Effects of 
Discharges from Oil and Gas Operations, March 1985.)
2. Selection of Pollutant Parameters
    EPA has selected free oil as the pollutant parameter for control of 
deck drainage. The specific conventional, toxic and nonconventional 
pollutants found to be present in deck drainage are those primarily 
associated with oil, with the conventional pollutant oil and grease 
being the primary constituent. In addition, other chemicals used in the 
drilling and production activities and stored on the structures have 
the potential to be found in deck drainage. EPA believes that an oil 
and grease limitation together with incorporation of site specific Best 
Management Practices, as required under the stormwater program and as 
discussed below, will control the pollutants in this wastestream.
    The specific conventional, toxic, and nonconventional pollutants 
controlled by the prohibition on the discharges of free oil are the 
conventional pollutant oil and grease and the constituents of oil that 
are toxic and nonconventional pollutants (see previous discussion in 
Section VI.B. describing the chemical constituents of oil). EPA has 
determined that it is not technically feasible to control these toxic 
pollutants specifically, and that the limitation on free oil in deck 
drainage reflects control of these toxic pollutants at the BAT and 
BADCT (NSPS) levels.
3. Control and Treatment Technologies
     a. Current Practice.
    BPT limitations for deck drainage prohibit the discharge of free 
oil. All equipment and deck space exposed to stormwater or washwater 
are surrounded with berms or collars. These berms capture the deck 
drainage where it flows through a drainage system leading to a sump 
tank. Initial oil/water separation takes place in the sump tank which 
is generally located beneath the deck floor or underground at land-
based operations. Effluent from the sump tank may be directed to a skim 
pile, where additional oil/water separation occurs. (The skim pile is 
essentially a vertical bottomless pipe with internal baffles to collect 
the separated oil.)
    The deck drainage treatment system is a gravity flow process, and 
the treatment tanks generally do not require a power source for 
operation. Thus, deck drainage generated at operations located in 
powerless, remote situations, (such as satellite wellheads) can be 
effectively treated.
    The difficulties in obtaining a representative sample of deck 
drainage effluent (due to their submerged or underground location) 
preclude the use of the static sheen test for this wastestream. Thus, 
free oil is measured by the visual sheen test. Deck drainage treatment 
is discussed in more detail in the Coastal Technical Development 
Document.
    b. Additional Technologies Considered.
    EPA knows of no additional technologies for the treatment of deck 
drainage. However, EPA, as described in the proceeding section, has 
determined that deck drainage could in some circumstances be commingled 
with either produced water or drill fluids and thus, could become 
subject to the limitations imposed on these major wastestreams. EPA has 
also considered requiring best management practices (BMPs) on either a 
site-specific basis or as part of the Coastal Guidelines (See 
discussion under part 6.b. in this Section).
4. Options Considered
    EPA has developed two options for the control of deck drainage. 
These are (1) establish limitations equal to BPT; or (2) establish 
limitations for the ``first flush'' of deck drainage equal to those for 
the major wastestreams it can be commingled with, and limitations equal 
to BPT after the first flush.
    In addition to BPT technology described above, EPA examined 
additional treatment control options based on current industrial 
practices. The 1993 Coastal Oil and Gas Questionnaire as well as the 
industry site visits reveal that deck drainage is often commingled with 
produced waters prior to discharge or injection. Because 
[[Page 9456]] of this practice, EPA investigated an option requiring 
capture of the ``first flush'', or most contaminated portion of, deck 
drainage. Depending on whether the deck drainage is generated from 
drilling or production (actual hydrocarbon extraction) operations, this 
first flush would be subject to the same limitations as would be 
imposed on either produced water or drilling fluids and cuttings based 
on the assumption that these two wastestreams could be commingled. 
Thus, for deck drainage during production, EPA considered as an option 
zero discharge for the first flush everywhere except in Cook Inlet, 
where oil and grease limitations would apply. Zero discharge would be 
required for the first flush captured at drilling operations 
everywhere. After capturing the first flush, BPT limitations would 
apply to any remaining deck drainage at either production or drilling 
operations. Capture of all of deck drainage to meet zero discharge 
requirements would be impractical due to relatively heavy precipitation 
that occurs in the Gulf areas.
    EPA considered employing a 500 barrel tank to capture the first 
flush. A tank of this size would be installed at production facilities, 
and would provide enough storage capacity to capture most, if not all, 
of the rainfall generated during a 3.5 inch rainfall event at an 
average size facility. Tanks smaller than 500 bbls would not be large 
enough to effectively capture the first flush of contaminated drainage. 
Tanks larger than this would be too costly to install. A 3.5 inch, 24 
hour rainfall event would generally only be exceeded once per year in 
southern Louisiana (the coastal area receiving the most rainfall), and 
at most, two to three times. After collection, the 500 barrels (or less 
depending on the size storm event) of deck drainage would be directed 
through the produced water treatment and would be subject to the same 
limitations as required for produced water.
    For drilling operations, the first 500 barrels would be subject to 
zero discharge. The basis for this requirement would be that the deck 
drainage would be directed to on-site drilling waste collection vessels 
or levees where they would be sent off-site for commercial disposal.
    After collection and treatment of the first 500 bbls of deck 
drainage, any remaining discharge would be subject to the BPT 
limitations on free oil as measured by the visual sheen test.
    The first flush option for deck drainage is estimated to eliminate 
discharge of more than 9 million bpy of deck drainage (about 78 percent 
of the total currently discharged) resulting in the removal 82,000 
pounds per year of oil and grease.
5. BCT Option Selection
    EPA conducted the BCT cost test (described previously in Section 
VI) for the two deck drainage options. The first flush option did not 
pass the POTW cost test. The result of this test analysis ranged from 
$2.13 to $3.45 per pound, and to pass the test, this value must be less 
than $0.534 per pound.
    Thus, EPA has selected BPT, or a limitation prohibiting the 
discharge of free oil as the BCT limit, for deck drainage. This is a 
no-cost option because it reflects current practice. It is cost 
reasonable under the BCT cost test because the POTW test result and the 
industry cost-effectiveness test results are both zero (and therefore 
pass their respective tests).
6. Rationale for Selection BAT, NSPS, PSES and PSNS
    a. Cost.
    No costs are incurred by compliance with the option to require BPT 
limits for deck drainage. Costs to comply with the first flush option 
for operations in the Gulf of Mexico would be approximately $13.5 
million per year. This includes the costs for both production and 
drilling operations to comply with a zero discharge requirement for the 
first flush followed by BPT for any remaining discharge after that. 
Costs to comply with this option for the Cook Inlet would be 
approximately $699,000 per year. This includes the costs of treating 
the first flush of deck drainage with produced water to meet oil and 
grease limitations of 29 mg/l 30-day average, and 42 mg/l daily 
maximum, followed by BPT for any remaining discharge after that. Total 
costs for this option would be approximately $14.2 million per year.
    b. Rationale for Selection of BAT and NSPS.
    EPA has selected BPT as its preferred option for BAT and NSPS for 
deck drainage. Since free oil discharges are already prohibited under 
BPT, there are no incremental compliance costs, pollutant removals, or 
non-water quality environmental impacts associated with this control 
option. Since this preferred option limits free oil equal to existing 
BPT standards, it is technologically available and economically 
achievable.
    EPA has rejected the first flush option for control of deck 
drainage for several reasons primarily relating to whether this option 
is technically available to operators throughout the coastal 
subcategory. Deck drainage is currently captured by drains and flows 
via gravity to separation tanks below the deck floor. However, the 
problems associated with capture and treatment beyond gravity feed, 
power independent systems, are compounded by the possibilities of back-
to-back storms which, may cause first flush overflows from an already 
full 500 bbl tank. In addition, tanks the size of 500 barrels are too 
large to be placed under deck floors. Installation of a 500 bbl tank 
would require construction of additional platform space, and the 
installation of large pumps capable of pumping sudden and sometimes 
large flows from a drainage collection system up into the tank. The 
additional deck space would add significantly, especially for water-
based facilities, to the cost of this option. Further, many coastal 
facilities are unmanned and have no power source available to them. 
Deck drainage can be channelled and treated without power under the BPT 
limitations.
    Capturing deck drainage at drilling operations poses additional 
technical difficulties. Drilling operations on land may involve an area 
of approximately 350 square feet. A ring levee is typically excavated 
around the entire perimeter of a drilling operation to contain 
contaminated runoff. This ring levee may have a volume of 6,000 bbls, 
sufficient to contain 500 bbls of the first flush. However, collection 
of these 500 bbls when 6,000 bbls may be present in the ring levee 
would not effectively capture the first flush. Costs to install a 
separate collection system including pumps and tanks, would add 
significantly to the cost of this option.
    While costs are significant, the technological difficulties 
involved with adequately capturing deck drainage at coastal facilities 
is the principal reason why this option was not selected. EPA has 
selected the option requiring no discharge of free oil for BAT and NSPS 
control of deck drainage. EPA has determined that these limitations and 
standards properly reflect BAT and NSPS levels of control. EPA did not 
identify any other available technology for this waste stream. EPA 
solicits comments on the existence and practicality of treatment 
systems other than BPT.
     EPA's proposed option does not include best management practices 
(BMPs) for this wastestream as part of these guidelines. EPA currently 
believes that current industry practices, in conjunction with the 
requirements as proposed in the proposed general stormwater rule (58 FR 
61262-61268, November 19, 1993), would be sufficient to minimize the 
introduction of contaminants to this wastestream to the extent 
possible. These stormwater [[Page 9457]] requirements, if promulgated 
as proposed, would require an oil and gas operator to develop and 
implement a site-specific storm water pollution prevention plan 
consisting of a set of BMP's depending on specific sources of 
pollutants at each site. As noted in the stormwater proposal, the two 
types of BMP's most effective in reducing storm water contamination are 
to minimize exposure (e.g., covering, curbing, or diking) and treatment 
type BMP's which are used to reduce or remove pollutants in storm water 
discharges (e.g., oil/water separators, sediment basins, or detention 
ponds).
    EPA solicits comment as to whether BMPs should be required for deck 
drainage as part of the Coastal Guidelines. Such BMPs may include (1) 
segregation of deck drainage from oil leaks from pump bearings and 
seals by using drip pans and other collection devices, (2) segregation 
of contaminated process area deck drainage and runoff from relatively 
uncontaminated runoff from areas such as living quarters, and walkways, 
(3) installation of roofs and sheds to divert uncontaminated rainfall 
from areas with a high potential for generating contaminated runoff, 
(4) careful handling of drilling fluid materials and treatment 
chemicals to prevent spills, (5) use of local containment devises such 
as liners, dikes and drip pans where chemicals are being unpackaged and 
where wastes are being stored and transferred.
7. PSES and PSNS
    EPA is proposing to limit PSES and PSNS for deck drainage as zero 
discharge. EPA believes that zero discharge for PSES and PSNS is 
preferable to establishing a limit equal to BPT because generally slugs 
of deck drainage would interfere with biological treatment processes at 
POTW's. This is discussed further in the Coastal Technical Development 
Document. In addition, EPA did not have sufficient data to conduct a 
pass through analysis of the pollutants found in deck drainage for the 
reasons discussed further in the Coastal Technical Development 
Document. EPA solicits comments and data on this issue. Moreover, 
technical difficulties associated with capture of deck drainage that 
make it difficult to require limitations other than the BPT, no free 
oil limit makes it unlikely that this wastestream would be sent to 
POTW's. EPA solicits comment on whether it would be possible for 
collection of deck drainage and transmission to a POTW to occur.
E. Treatment, Workover, and Completion Fluids

1. Waste Characterization
    Well treatment, workover, and completion fluids are primarily 
generated during production. Well treatment and workover fluids are 
inserted downhole in a producing well to increase a well's productivity 
or to allow safe maintenance of the well. Completion fluids are also 
inserted downhole after a well has been drilled, and serve to clean the 
wellbore, and maintain pressure prior to production. In most 
operations, these fluids resurface once production is initiated and can 
either be reused, or must be disposed of.
    According to results obtained in the 1993 Coastal Oil and Gas 
Questionnaire, EPA estimates that approximately 275,000 bbls (205,000 
and 70,000 bpy of treatment/workover and completion fluids 
respectively) or these fluids are discharged annually from coastal oil 
and gas operations in Texas and Louisiana. This amounts to an average 
of 587 bbls of treatment and workover fluids discharged per year, per 
well, from approximately 350 wells. For completion fluids, this amounts 
to an average of 209 bbls discharged per year per well from 334 wells. 
The 1993 Questionnaire also provides information showing that 
treatment, workover and completion fluids discharged are commingled 
with the produced water in Texas and Louisiana prior to injection or 
discharge. Florida, Alabama and North Slope coastal oil and gas 
operators do not discharge these fluids.
    Based on the 1993 Coastal Oil and Gas Questionnaire and EPA's 
Region X Discharge Monitoring Reports (described in Section V) all Cook 
Inlet operators commingle these fluids with produced water for 
treatment prior to discharge.
    The composition of the discharges is highly dependent on the 
fluid's purpose, but they generally consist of acids (in the case of 
treatment) or weighted brines (for workover of completion). The 
principal pollutant in these fluids is oil and grease ranging in 
concentration from 15-722mg/l. Total suspended solids, another major 
constituent in these fluids, is present in concentrations ranging from 
65 to 1600 mg/l. Prominent priority metals that exist in these wastes 
include chromium, copper, lead, and zinc. Priority organics are also 
present including acetone, benzene, ethylbenzene, xylene, toluene, and 
naphthalene.
    EPA estimates that, approximately 22,000 pounds of oil and grease, 
50,000 pounds of TSS, 292 pounds of toxic metals, and 417 lbs of toxic 
organics are being discharged annually in the Gulf of Mexico. In 
addition, approximately 3.4 million pounds of nonconventionals are 
being discharged including boron, calcium, cobalt, iron, manganese, 
molybdenum, tin, vanadium, and yttrium.
2. Selection of Pollutant Parameters
    Where zero discharge would be required, EPA would be regulating all 
conventional, toxic, and non-conventional pollutants found in well 
treatment, completion and workover fluids.
    In Cook Inlet, where discharge would be allowed under Option 2, the 
parameter ``oil and grease'' would be regulated as an indicator for 
toxic pollutants. EPA has data indicating that the control of oil and 
grease will control certain toxic pollutants (including phenol, 
naphthalene, ethylbenzene, toluene and zinc) as discussed in the 
Offshore Technical Development Document. As presented in Section VI of 
the Offshore Technical Development Document when discussing the 
prohibitions on the discharge of free oil, removal of oil from the 
discharge effectively removes certain toxic pollutants. Free oil is 
considered to be ``indicator'' for the control of specific toxic 
pollutants present in complex hydrocarbon mixtures. These pollutants 
include benzene, toluene, ethylbenzene, naphthalene, phenanthrene, and 
phenol.
    Under EPA's proposed BCT limits, applicable to conventional 
pollutants, EPA would prohibit the discharge of ``free oil,'' as 
determined by the static sheen test. EPA would prohibit discharge of 
``free oil'' as a surrogate for control over the conventional pollutant 
``oil and grease'' in recognition of the complex nature of the oils 
present in drilling fluids, including crude oil from the formation 
being drilled.
    As will also be discussed below, EPA has determined that it is not 
feasible to regulate separately each of the constituents in these 
fluids because these fluids in most instances become part of the 
produced water wastestream and take on the same characteristics as 
produced water. Due to the variation of types of fluids used, the 
volumes and their correspondingly variable constituent concentrations, 
EPA believes it is impractical to measure and control each individual 
parameter.
    While the oil and grease and, in certain instances, the no free oil 
limitations limit the discharges of toxic and conventional pollutants 
found in well treatment, completion and workover fluids, certain other 
pollutants [[Page 9458]] are not controlled. EPA proposes to exercise 
its discretion not to regulate these pollutants because EPA has not 
detected them in more than a very few of the samples within the 
subcategory and the pollutants when found are present in trace amounts 
not likely to cause toxic effects. This is consistent with EPA's 
findings in the Offshore Guidelines. (See EPA's data base for these 
fluids in the Coastal Technical Development Document).
3. Control and Treatment Technologies
    Current practice in the control of discharges from these fluids is 
to meet the BPT limitations of no free oil (using the visual sheen 
test). EPA's final general permit applicable to the discharges from 
coastal oil and gas drilling operations in Texas and Louisiana further 
prohibits discharges of treatment, workover and completion fluids to 
freshwater areas. Methods for treatment and discharge, reuse or 
disposal include:
    * Treatment and disposal along with the produced water
    * Neutralization for pH control and discharge to surface waters
    * Reuse
    * Onshore disposal and/or treatment and discharge in coastal or 
offshore areas.
4. Options Considered
    EPA has considered two options for the treatment of treatment, 
workover, and completion fluids. These are (1) Prohibit the discharges 
of free oil (equal to the BPT limits) and prohibit the discharges of 
these fluids to freshwaters of Texas and Louisiana, (2) Limit the 
discharges equal to EPA's preferred options for produced waters. For 
produced water BAT limits, EPA is proposing zero discharge everywhere 
except Cook Inlet, where the proposed produced water control option is 
to meet limitations on oil and grease of 42 mg/l daily maximum and 29 
mg/l 30-day average. For NSPS, PSES, and PSNS, EPA is proposing zero 
discharge everywhere for produced water.
    There are no additional costs to comply with Option 1 because it 
reflects the current requirements imposed on the industry.
    Option 2 would require for BAT, that zero discharge be met for 
treatment, completion, and workover fluids for all areas except the 
Cook Inlet, where operators are currently commingling these wastes with 
produced water, and would be required to meet oil and grease 
limitations of 29 mg/l 30-day average and 42 mg/l daily maximum. This 
would annually remove 72,000 pounds of conventionals, 709 pounds of 
priority toxic pollutants and an additional 3.4 million pounds of 
nonconventional pollutants. For NSPS, EPA would require zero discharge 
everywhere, including Cook Inlet. This would remove annually 9,400 
pounds of conventionals, 92 pounds of priority toxic pollutants and an 
additional 440,000 pounds of nonconventional pollutants. EPA is not 
applying a separate cost in Cook Inlet to comply with this option 
because these costs are already included in the costs of complying with 
the produced water option for Cook Inlet (oil and grease limits of 29 
mg/l 30-day average/42 mg/l daily maximum).
    However, for the Gulf, costs attributed to this option would be 
operating and maintenance costs associated with commingling with 
produced water and on-site injection, or hauling off-site to a 
commercial disposal facility if commingling is not possible. In costing 
this option for the Gulf, EPA estimated that 77 percent of treatment, 
workover and completion fluids currently being discharged would be 
commingled with produced water. This estimate comes from information 
indicating that 77 percent of produced water discharges are flows 
greater than 110 bpd (See Section VI) and would be disposed of by 
onsite injection because flows greater than 110 bpd will be large 
enough to accommodate the introduction of treatment, workover and 
completion fluids without fouling the produced water treatment system. 
The other 23 percent are less than 110 bpd and therefore it would be 
more cost effective to send the produced waters off-site for disposal 
rather than install an injection well. (See the Coastal Technical 
Development Document, Section XII).
    Based on these estimates, EPA calculated the costs of compliance 
with Option 2. These costs included operating and maintenance costs on 
a dollar per bbl basis for on-site commingling and injection with 
produced water, and costs of transportation and disposal for commercial 
disposal. The BAT limits would cost approximately $610,000 annually in 
the Gulf.
    Costs for NSPS requiring zero discharge for treatment, workover and 
completion fluids were calculated based on EPA's estimate that 187 new 
wells will be drilled per year in the Gulf Coast (this estimate was 
obtained from the 1993 Coastal Oil and Gas Questionnaire results). Of 
these 187, EPA estimated that 76 percent (142 facilities) would be 
located in Louisiana freshwaters and would not discharge due to state 
water quality standards (this estimate is also based on the 
Questionnaire results). The remaining 45 facilities would each generate 
approximately 800 bbls of treatment, workover and completion fluids per 
year. Costs to meet zero discharge, based on commingling these fluids 
with produced water or directing them separately to commercial disposal 
facilities, are estimated to be approximately $520,000 per year over 
the next 15 years. These costs are only for the Gulf coast operations. 
No new sources are expected to be installed in Cook Inlet.
5. Rationale for Selection of Proposed Regulations
    a. BCT, BAT, and NSPS.
    EPA is proposing to establish BCT limitations equal to BPT, 
prohibiting the discharge of free oil in well treatment, workover, and 
completion fluids. Compliance with this limitation would be determined 
by the static sheen test. Since BPT reflects current practice, this 
proposed BCT limitation is cost reasonable under the BCT cost test. 
Based on the available data regarding the levels of conventional 
pollutants present in these wastes, EPA did not identify any other 
options which would pass the BCT cost test other than establishing BCT 
equal to the existing BPT limits. Additional information regarding the 
results of the BCT cost test for these wastes is presented in the 
Coastal Technical Development Document. There are no costs or non-water 
quality environmental impacts associated with this proposed BCT 
limitation and, since it is equal to BPT, it is technologically 
available and economically achievable.
    EPA is co-proposing both options considered for well treatment, 
workover, and completion fluids for BAT and NSPS. EPA has determined 
that both options are technologically and economically achievable and 
have acceptable non-water quality impacts.
    However, due to the high cost effectiveness results for Option 2 
(requiring the same limitations as proposed for produced water) a 
preferred option has not been selected. EPA solicits comment on the 
appropriateness of either option. Option 1, which would prohibit the 
discharge of free oil and prohibit the discharge of treatment, workover 
and completion of fluids to freshwaters of Texas and Louisiana, 
reflects current regulatory requirements and thus will incur no 
additional compliance costs, economic or non-water quality 
environmental impacts. This option would result in no incremental 
removal of pollutants from this wastestream beyond the existing BPT 
requirements. [[Page 9459]] 
    Option 2 would require for BAT zero discharge of treatment, 
completion, and workover fluids except for Cook Inlet, where EPA would 
establish oil and grease limitations of 29 mg/l 30-day average, 42 mg/l 
daily maximum. For NSPS, this option would require zero discharge of 
all treatment, completion, and workover fluids from all new sources.
    Zero discharge is being achieved by many operators (except those in 
Texas, saline waters of Louisiana, and Cook Inlet) for the treatment, 
workover, and completion fluids wastestream. The technology basis for 
zero discharge is commingling this wastestream with produced water or 
sending it separately to off-site commercial disposal facilities. For 
Cook Inlet, this option, which also contains allowable discharge 
limitations is based on commingling with produced water, because 
commingling of these wastestreams is currently occurring in this area. 
The specific oil and grease limits proposed are technologically 
available for the same reasons they are available for control of 
produced water, as discussed above.
    The zero discharge limitation would eliminate all discharges of 
toxic, conventional, and nonconventional pollutants. The oil and grease 
limits would be technologically based on improved gas flotation 
performance (See Section VI.B. of this preamble) and serve to limit the 
discharge of toxic and conventional pollutants to surface waters.
    Zero discharge for treatment, workover and completion fluids in 
Cook Inlet was not selected for this BAT option because these fluids 
are commingled with produced water as an integral part of their 
operations, and because zero discharge for produced water was 
determined to be uneconomical for Cook Inlet operators.
    The costs to meet Option 2 for BAT ($610,000) are relatively 
minimal since this amount is negligible in comparison to total annual 
production revenue from Gulf coastal operations.
    Costs to achieve zero discharge everywhere for Option 2 NSPS are 
expected to be negligible. Out of the 187 new wells that will be 
drilled in the Gulf Coast, 76 percent will not discharge these fluids 
in freshwaters because of water quality standards requirements. The 
remaining 45 facilities will each generate approximately 800 bbls of 
treatment, workover and completion fluids per year (estimates of 
volumes from the 1993 Coastal Oil and Gas Questionnaire). While some of 
these fluids may be directed for treatment and disposal to existing 
production facilities, EPA is conservatively estimating costs of the 
Option 2 NSPS assuming all of these fluids would be directed to new 
production facilities for treatment and disposal (or be treated on-site 
at the new source). For the Gulf, the NSPS requirements under this 
Option 2 would be the same as those for BAT, thus costs would either be 
equal to BAT, or less than BAT since new sources can more efficiently 
design their facilities to comply with zero discharge. Costs for new 
sources in the Gulf generating treatment, workover and completion 
fluids to meet zero discharge would be approximately $520,000 per year 
which is negligible in relation to annual production revenue from Gulf 
coastal operators.
    For Cook Inlet, costs to meet Option 2 requirements for treatment, 
workover and completion fluids are included in the cost analysis for 
produced water because current practice there is commingling of these 
wastestreams (See Section VI.E.). While EPA does not anticipate any new 
sources to be constructed in Cook Inlet, and therefore has not 
attributed any costs to NSPS, the NSPS would not cause a significant 
barrier to entry. These impacts are only a small incremental increase 
over the impacts resulting from the controls on produced water and 
drilling fluids and cuttings. Finally the non-water quality 
environmental impacts of this Option 2 are believed to be acceptable, 
because like their volumes, they are relatively small (See Section VIII 
of this preamble) as discussed below.
    Option 2 would result in the removal of 3.9 million pounds of 
conventional, toxic and non-conventional pollutants annually (a total 
of 2140 in toxic pound equivalents). However the amount of toxic 
priority pollutants removed is approximately 0.02 percent of this 
total. The annual compliance costs of $1.1 million (for BAT and NSPS 
combined) to remove 800 pounds of priority toxic pollutants indicates 
that this option is not cost effective. (See also EPA's cost 
effectiveness analyses entitled Cost Effectiveness Analysis of Effluent 
Limitations Guidelines and Standards for the Coastal Oil and Gas 
Industry found in the rulemaking record for this proposal).
    EPA is soliciting comments on whether the volumes of treatment, 
workover and completion fluids removed by these options are deminimus, 
and on the applicability, achievability and practicality of both 
Options 1 and 2.
    b. PSES and PSNS.
    Pretreatment standards for treatment workover and completion fluids 
are being proposed equal to zero discharge. This is because their 
chemical composition, like produced water, tends to be high in total 
dissolved solids which may interfere with POTW operations. EPA did not 
have sufficient data, however, to conduct a pass-through analysis for 
the pollutants contained in this wastestream. Both interference and 
pass-through are discussed further in the Coastal Technical Development 
Document. EPA solicits comments on these issues. Zero discharge for 
NSPS would not pose barrier to entry for the same reason as discussed 
under NSPS for this wastestream.
    EPA solicits comments on both the occurrence of treatment, workover 
and completion fluid discharges into POTW's and the appropriateness of 
pretreatment standards requiring zero discharge for this wastestream.

F. Domestic Wastes

    Domestic wastes result from laundries, galleys, showers, etc. 
Detergents are often part of this wastestream. Waste flows may vary 
from zero for intermittently manned facilities to several thousand 
gallons per day for large facilities.
    The conventional pollutant of concern in domestic waste is floating 
solids. The BPT limitations for deck drainage are no discharge of 
floating solids. To comply with this limit, domestic waste is ground up 
so as not to cause floating solids on discharge. EPA is proposing to 
limit floating solids as well for BCT and NSPS. In addition, EPA is 
proposing to prohibit discharges of foam for BAT and NSPS. Foam is a 
nonconventional pollutant and its limitation is intended to control 
discharges that include detergents.
    EPA is also proposing to limit discharges of garbage as included in 
U.S. Coast Guard regulations at 33 CFR Part 151. These Coast Guard 
regulations implement Annex V of the Convention to Prevent Pollution 
from Ships (MARPOL) and the Act to Prevent Pollution from Ships, 33, 
U.S.C. 1901 et seq. (The definition of ``garbage'' is included in 33 
CFR 151.05).
    The pollutant limitations described above for domestic wastes are 
all technologically available and economically achievable and reflect 
the BCT, BAT and NSPS levels of control. Under the Coast Guard 
regulations, discharges of garbage, including plastics, from vessels 
and fixed and floating platforms engaged in the exploration, 
exploitation and associated offshore processing of seabed mineral 
resources are prohibited with one exception. Victual waste (not 
including plastics) may be discharged from fixed [[Page 9460]] or 
floating platforms located beyond 12 nautical miles from nearest land, 
if such waste is passed through a screen with openings no greater than 
25 millimeters (approximately one inch) in diameter. Because vessels 
and fixed and floating platforms must comply with these limits, EPA 
believes that all coastal facilities are able to comply with this 
limit. While not all coastal facilities are located on platforms, 
compliance with a no garbage standard should be as achievable, if not 
more so for shallow water or land based facilities that have access to 
garbage collection services. Further, the final drilling permit 
promulgated by Region VI for coastal Texas and Louisiana incorporates 
these Coast Guard regulations.
    Since these BCT, BAT and NSPS limitations for domestic waste are 
already in either existing NPDES permits or Coast Guard regulations, 
these limitations will not result in any additional compliance cost, 
and thus these limits are economically achievable. Also, these limits 
and standards will have no additional non-water quality environmental 
impacts. There are no incremental costs associated with the BCT 
limitations; therefore, it is considered to pass the two part BCT cost 
reasonableness test.
    No discharge of visible foam is required by Region X's NPDES permit 
for Cook Inlet drilling. No discharge of floating solids is included in 
the Region X's BPT Cook Inlet general permit, the Region X's drilling 
permit and Region IV's general permit for coastal operators.
    Pretreatment standards are not being developed for domestic wastes 
because they are compatible with POTWs.

G. Sanitary Wastes

    Sanitary wastes from coastal oil and gas facilities are comprised 
of human body wastes from toilets and urinals. The volume of these 
wastes vary widely with time, occupancy, and site characteristics. A 
larger facility, such as an offshore platform, typically discharges 
about 35 gallons of sanitary waste daily. Sanitary discharges from 
coastal facilities would be expected to be less than this value since 
the manning levels at most coastal facilities is less than that at 
offshore locations.
    Existing BPT limitations for facilities continuously manned by 10 
or more people requires sanitary effluent to have a minimum residual 
chlorine content of 1 mg/l, with the chlorine concentration to remain 
as close to this level as possible. Facilities intermittently manned or 
continuously manned by fewer than 10 people must comply with a BPT 
prohibition on the discharge of floating solids. EPA's Regions VI and 
IV NPDES general permits for coastal facilities also impose limits on 
the discharge of TSS, fecal coliform count, BOD and floating solids. 
EPA's Region X general NPDES permit for Cook Inlet also requires 
limitations for these same parameters in addition to requirements for 
foam and free oil.
    EPA considered zero discharge of sanitary wastes based on off-site 
disposal to municipal treatment facilities or injection with other oil 
and gas wastes. Off-site disposal would require pump out operations, 
that while available to certain land facilities, are not available to 
remote or water-based operations. Because sanitary wastes are not 
exclusively associated with oil and gas operations, which are routinely 
injected in Class II wells, zero discharge based on Class II injection 
was not considered for sanitary wastes. EPA solicits comments on the 
selected option for sanitary wastes regarding the pollutant regulated, 
the limitation itself, and other possible disposal options, including 
marine sanitation devices that are designed to prevent discharge (Type 
III, 33 CFR 159.3(s)).
    EPA is proposing to limit sanitary waste discharges for BCT and 
NSPS equal to BPT limitations. Sanitary waste effluents from facilities 
continuously manned by ten (10) or more persons must contain a minimum 
residual chlorine content of 1 mg/l, with the chlorine level maintained 
as close to this concentration as possible. Coastal facilities 
continuously manned by nine or fewer persons or only intermittently 
manned by any number of persons must comply with a prohibition on the 
discharge of floating solids.
    Since there are no increased control requirements beyond those 
already required by BPT effluent guidelines, there are no incremental 
compliance costs or non-water quality environmental impacts associated 
with BCT and NSPS limitations for sanitary wastes. Since these 
limitations are equal to BPT, they are available and economically 
achievable. In addition, the BCT limitation is also considered to be 
cost reasonable under the BCT cost test. Since the POTW test result and 
the industry cost-effectiveness test results are both zero (and 
therefore pass their respective tests), the limitation is cost 
reasonable.
    EPA is not establishing BAT effluent limitations for the sanitary 
waste stream because no toxic or nonconventional pollutants of concern 
have been identified in these wastes.
    Pretreatment standards are not being developed for sanitary wastes 
because they are compatible with POTWs.

VII. Economic Analysis

A. Introduction

    EPA's economic impact assessment is presented in the Economic 
Impact Analysis of Proposed Effluent Limitations and Guidelines, and 
Standards for the Coastal Oil and Gas Industry (hereinafter, ``EIA''). 
This report details the investment and annualized costs of compliance 
with the rule for the industry as a whole and the impacts of the 
compliance costs on affected wells, platforms, and operators in the 
coastal oil and gas industry, both existing and future. The report also 
estimates the economic effect of compliance costs on Federal and State 
revenues, balance of trade considerations, and inflation.
    EPA also has conducted an analysis of the cost-effectiveness of 
alternative treatment options. The results of the cost-effectiveness 
analysis are expressed in terms of the incremental costs per pound-
equivalent removed. Pound-equivalents account for the differences in 
toxicity among the pollutants removed. Total pound-equivalents are 
derived by taking the number of pounds of a pollutant removed and 
multiplying this number by a toxic weighting factor. The toxic 
weighting factor is derived using ambient water quality criteria and 
toxicity values. The toxic weighting factors are then standardized by 
relating them to a particular pollutant, in this case copper.
    Cost-effectiveness is calculated as the ratio of incremental 
annualized costs of an option to the incremental pound-equivalents 
removed by that option. This analysis, Cost-Effectiveness Analysis of 
Effluent Limitations Guidelines and Standards for the Coastal Oil and 
Gas Industry (hereinafter, the ``CE Report''), is included in the 
record of this rulemaking. Since the discharges are primarily to a 
marine or brackish environment, salt-water toxic weighting factors 
(which typically are lower than freshwater toxic weighting factors, 
thus they generate lower pound-equivalents overall) were used wherever 
they were available.
    Cost-effectiveness is a measure of costs and relative economic 
efficiency of the technology options being considered to remove toxic 
pollutants. EPA includes direct compliance costs, such as capital 
expenditures, operations and maintenance costs and in some cases 
monitoring costs (i.e., direct compliance costs), when estimating cost-
effectiveness. EPA has not included in previous effluent guidelines and 
standards costs associated with the economic impact of the technology 
[[Page 9461]] options in the costs used in the cost-effectiveness 
analysis. Consistent with this, for this effluent guidelines, EPA has 
included capital expenditures and operation and maintenance, but not 
the cost of the lost oil/gas production in its analysis of the 
incremental cost-effectiveness of different technology options. EPA 
does consider the lost production as an economic impact on this 
industry, and has included lost production in its economic impact 
analysis. During the interagency review a question was raised whether 
EPA should treat the lost oil/gas production as a compliance cost to 
the facility. EPA solicits comments on: (1) Whether the possibly 
permanent loss in oil/gas production associated with premature closing 
of these wells may be different from lower production of manufacturing 
goods that occurs in any production period as a result of higher 
production costs, and (2) whether or not the lost production of oil/gas 
should be considered when determining the cost-effectiveness on the 
technology options for this industry.

B. Economic Methodology

    The EIA provides the results of a number of measures of economic 
impact resulting from the proposed Coastal Guidelines. These measures 
include production losses (measured in terms of total lifetime 
production lost, losses in net present value (NPV)2 of production, 
and years of production lost), impacts on federal and state revenues; 
impacts on firms; impacts on employment; impacts on inflation and 
balance of trade; impacts on small businesses; and impacts on new 
sources in terms of barriers to entry. All impacts measured in this EIA 
do not take into account the requirements of the EPA Region VI General 
Permits for the Coastal Oil and Gas Industry covering disposal of 
produced water.

    \2\Net present value is the total stream of production revenues 
minus costs over a period of years discounted back to present value, 
under the assumption that a future dollar is worth less than a 
dollar now.
---------------------------------------------------------------------------

    These impacts are also based on the assumption that oil prices will 
remain, in real terms, approximately $18 per barrel over the timeframe 
of the analysis. This assumption is substantiated, at least for this 
decade, by recent industry forecasts. Note that if the price of oil 
changes significantly, impacts could also change.
1. Gulf of Mexico
    EPA used the 1993 Coastal Oil and Gas Questionnaire authorized 
under section 308 of the CWA to obtain the information necessary to 
model impacts at wells determined to be currently discharging and which 
were determined to be continuing to discharge at least through the 
third quarter of 1996. Incremental compliance costs specific to these 
wells or the produced water separation and treatment facilities 
associated with these wells (prorated on a cost per barrel basis to 
make them well-specific) were used to derive the incremental costs to 
the affected wells. By Gulf of Mexico, the EIA does not generally 
include Gulf coastal facilities in Alabama and Florida, since coastal 
operators in these states are already required to meet zero discharge, 
and thus, these facilities would not incur additional costs from this 
rule.
    A financial model showing cash flow over a maximum 30-year time 
frame (or less if a well's flow becomes negative before 30 years) was 
developed and adapted to each well using well-specific data in the 
Questionnaire. Costs included in the models include those associated 
with current production costs and revenues, which were extrapolated 
over the lifetime of the project to establish baseline lifetime 
production. Other baseline summary statistics included years of 
economic lifetime, corporate cost per barrel of oil equivalent (BOE), 
and net present value of lifetime production. Then, capital and annual 
operating and maintenance (O&M) costs associated with various 
regulatory options were added to the baseline costs. The model 
recalculates the economic lifetime of the wells, annualizes the 
regulatory costs over the new project lifetime, and recalculates 
production and financial summary statistics. Well impacts were 
evaluated by determining the change from the baseline values caused by 
the increased regulatory costs. Production losses are measured as 
reductions in hydrocarbon extraction resulting from immediate closure 
of existing wells and curtailed lifetimes. These were based on the 
decrease in production and decrease in net present values for the wells 
induced by the regulatory costs. That is, if a well became unprofitable 
with the additional costs, it was assumed to shut in, either in the 
first year or earlier than it might have under baseline assumptions.
    To provide more accuracy in estimating the total annual costs to 
the Gulf of Mexico (GOM) coastal oil and gas industry, these costs were 
derived using state permit data on discharging facilities and 
compliance cost estimates developed on a per-facility basis. Thus costs 
were not based on extrapolations from survey data. These costs are pre-
tax (although the financial models account for impacts based on the 
appropriate post-tax costs). EPA re-emphasizes that this analysis 
assumes that the Region VI permit for produced water is not part of the 
baseline scenario.
    EPA also analyzed secondary impacts of the regulation. These 
include: revenue losses to the federal government due to tax shields on 
expenditures and loss of taxable revenues, revenue losses to State 
governments through lower severance tax payments and royalties, changes 
in the balance of trade and inflation, employment losses (both primary 
and secondary) based on production losses and firm failures, and 
employment gains (involved with manufacturing, installing, and 
operating pollution control equipment). Impacts on new sources also are 
investigated and a regulatory flexibility analysis is performed.
2. Cook Inlet
    The same type of financial model used in the Gulf of Mexico portion 
of the analysis was adapted to model 14 platforms (one currently shut 
in but with potential for future production) in the Cook Inlet. The 
same types of impacts from a variety of regulatory options for this 
region also were estimated. One difference between the Cook Inlet model 
and the Gulf model is that the Cook Inlet model operates at the 
platform level instead of the well level. Impacts are evaluated for 
platforms, whose production rates change with the addition of new and 
recompleted wells.

C. Summary of Costs and Economic Impacts

1. Overview of Economic Analysis
    The economic analysis has five major components: (1) An estimate of 
the number of existing wells (Gulf of Mexico) and platforms (Cook 
Inlet) and projected wells/platforms that incur costs under this rule; 
(2) an estimate of the annual aggregate (pre-tax) cost of complying 
with the regulation using capital and O&M costs per Cook Inlet platform 
or Gulf of Mexico treatment facility as estimated in the Development 
Document; (3) use of an economic model to evaluate per-well/platform 
impacts on production and economic life; (4) an evaluation of impacts 
on firms, future oil and gas production, Federal and State revenues, 
balance of trade, employment and other secondary effects; and (5) the 
performance of a regulatory flexibility analysis as required under the 
Regulatory Flexibility Act to determine whether impacts on small firms 
are disproportionate to those on large firms.

[[Page 9462]]

    The base year for the economic analysis is 1992, so all costs are 
reported in 1992 dollars. This is the year for which data were gathered 
in the 1993 Coastal Oil and Gas Questionnaire and was the most recent 
year for which a complete set of cost, revenue, and production data 
were available. Any costs not originally in 1992 dollars were inflated 
or deflated using the Engineering News Record Construction Cost Index, 
unless otherwise noted in the EIA (see EIA for details).
    The industry profile used in this analysis is presented in Section 
IV. EPA estimates that there are 4,675 existing wells in the Gulf of 
Mexico Coastal Region, of which 1,588 are estimated to still be 
discharging produced water in 1996, according to estimates based on 
Questionnaire 308 survey results. By Gulf of Mexico, EPA has not 
included Alabama or Florida since these facilities are currently 
meeting zero discharge. As noted above, this costing approach is 
conservative because independent of this rule, an additional 28 
production facilities (with an estimated 213 wells) in coastal 
Louisiana will be required by Louisiana state water quality standards 
to achieve zero discharge by January 1997. Six new production 
facilities are expected to be built each year in the Gulf region. The 
costs for these new projects are assigned as NSPS compliance costs. In 
Cook Inlet, no new facilities are anticipated, thus no NSPS costs are 
calculated for purposes of estimating the total costs of the rule. EPA 
has, however, analyzed whether the NSPS requirements for Cook Inlet 
would create a barrier to entry for any new sources that might begin to 
operate in Cook Inlet.
    EPA examined the effect of BPT, BCT, BAT, and NSPS regulatory 
options. BPT options have no costs or impacts and are discussed no 
further here. BCT options were examined using BCT cost tests (see 
Section VI). BAT and NSPS economic impacts are discussed in this 
section. The following wastestreams are regulated by this rule: 
produced water; drilling wastes; well treatment, workover, and 
completion fluids; produced sand; deck drainage; sanitary wastes; and 
domestic wastes. For sanitary and domestic wastes, the BAT and NSPS 
options proposed are current permit conditions, thus no costs or 
impacts are incurred as a result of BAT or NSPS requirements for these 
wastestreams. For deck drainage, the limits are based on BPT, thus 
costs and impacts of BAT or NSPS requirements are zero. For produced 
sand, current practice is zero discharge, and zero discharge is the 
only option considered for BPT, BAT or NSPS. Thus, no costs or impacts 
are expected to result from BAT or NSPS requirements for produced sand. 
Therefore, the remainder of this section discusses the costs and 
impacts of BAT and NSPS options only for produced water; drilling 
waste; and treatment, workover, and completion fluids.
    In all, there are 10 BAT regulatory options: 5 for produced water, 
3 for drilling wastes, and 2 for treatment, workover, and completion 
fluids. These options are described in Section VI. The economic impacts 
from these options are assessed individually in this Section. Selected 
NSPS options are also discussed in these sections.
2. Total Costs and Impacts of the Regulations
    This section presents the costs and impacts of the selected BAT and 
NSPS regulatory options. The total annual costs of the BAT and NSPS 
regulatory alternatives are presented in Table 6. Note that the costs 
and impacts of this rule would be substantially reduced if the effects 
of the recently finalized EPA Region VI General Permit were to be 
incorporated in this rule. The preferred BAT regulatory option for 
produced water is Option 4, zero discharge everywhere except in Cook 
Inlet where discharges are allowed provided oil and grease limitations, 
based on improved gas flotations, are met.

          Table 6.--Total Costs of BAT and NSPS Options (1992$)         
                                                                        
  ----------------------------------------------------------------------
(4) Annual compliance costs                                             
 ($ million/yr)                                                         
                            --------------------------------------------
       Wastestream\1\                                                   
(2) BAT                                                                 
(1) NSPS                                                                
------------------------------------------------------------------------
Produced water.............                                             
(2) 30.86                                                               
(1) 4.48                                                                
------------------------------------------------------------------------
                                                                        
(2) Co-proposal                                                         
(1)                                                                     
                            ---------------------------                 
                              Opt 1    Opt 2    Opt 3                   
(1) \2\ 0                                                               
                            ---------------------------                 
Drilling fluids and                                                     
 cuttings                       0       1.4      3.89                   
(1)                                                                     
------------------------------------------------------------------------
                                                                        
(2) Co-proposal                                                         
(1) Co-proposal                                                         
                            --------------------------------------------
                              Opt 1                                     
(1) Opt 2                     Opt 1    Opt 2                            
                            --------------------------------------------
Treatment, workover, and                                                
 completion fluids.........     0                                       
(1) 0.61                        0       0.52                            
------------------------------------------------------------------------
    Total..................                                             
(2) 30.86-35.36                                                         
(1) 4.48-5.00                                                           
                                                                        
------------------------------------------------------------------------
\1\EPA selected no-cost options for all other wastestreams.             
\2\No new sources expected in Cook Inlet.                               

    The three options considered for drilling fluids and cuttings BAT 
and NSPS contain zero discharge for all areas, except two of the BAT 
options contain allowable discharges for Cook Inlet. One of these 
options which would allow discharges meeting a more stringent toxicity 
limitation if selected for the final rule, would require an additional 
notice for public comment since the specific toxicity limitation has 
not been determined at this time. The three options are: Option 1--zero 
discharge for all areas except Cook Inlet where discharge limitations 
require toxicity of no less than 30,000 ppm (SPP), no discharge of free 
oil and diesel oil and no more than 1 mg/l mercury and 3 mg/l cadmium 
in the stock barite, Option 2--zero discharge for all areas except for 
Cook Inlet where discharge limitations would be the same as Option 1, 
except toxicity would be set to meet a limitation between 100,000 pm 
(SPP) and 1 million ppm (SPP), and Option 3--zero discharge for all 
areas. EPA is co-proposing two options for BAT and NSPS for treatment, 
workover and completion fluids. Option 1 would require no discharge of 
free oil and [[Page 9463]] prohibit discharges to freshwaters of Texas 
and Louisiana. This option reflects current practice. Option 2 would 
require the same limitations as the preferred option for produced 
water. This option would require for BAT that, discharges of treatment, 
workover and completion fluids would be prohibited in all coastal areas 
except Cook Inlet. In Cook Inlet, these discharges would be required to 
meet a daily maximum oil and grease limitation of 42 mg/l and a 30 day 
average of 29 mg/l. Option 2 would require zero discharged of these 
fluids everywhere for NSPS.
    The total cost of compliance with these selected BAT options is 
$30.9 million to $35.4 million per year in 1992$'s (or $33.5 million to 
$38.4 million in 1994$'s). Additionally, compliance with the BAT 
options would result in up to approximately $9.5 million in lost oil 
and gas revenues, taxes and royalties annually.3

    \3\The industry will not experience the entire impact of these 
costs because depreciation allowances and increased costs of 
production stemming from these compliance costs will serve to reduce 
taxable income. Thus a portion of these costs will be borne by 
federal and state governments rather than industry or individual 
firm owners. This portion is known as industry's ``tax shield.'' 
This impact to governments is, however, noted in the analyses 
discussed below.
---------------------------------------------------------------------------

    NSPS requirements for produced water is zero discharge (only the 
Gulf is expected to have new sources). The options being co-proposed 
for NSPS for drilling fluids and cuttings and treatment, workover and 
completion fluids are the same as those considered for BAT. Total 
compliance cost of NSPS for this proposal ranges from $4.48 to 
approximately $5 million annually in 1992 $'s (or $4.9 to $5.4 million 
annually in 1994 $'s). Additionally, compliance with the selected NSPS 
options could also result in roughly $1 to 2 million in lost oil and 
gas revenues, royalties and taxes annually. Costs of NSPS for produced 
water are associated only with six new source production facilities per 
year projected in the Gulf region. No new sources are projected in Cook 
Inlet. For the six new production facilities constructed per year in 
the Gulf, costs of the produced water NSPS are estimated to be 
approximately $4.48 million per year or $38.4 million (present value) 
over a 15-year time frame.
    Costs of NSPS for well treatment, workover and completion fluids 
are based on EPA projections that 45 new source wells would be 
discharging these fluids (without this rule) in the Gulf region. No new 
sources are projected in Cook Inlet. For the 45 new source wells in the 
Gulf region costs of the NSPS options for well treatment, workover and 
completion fluids are estimated to range from $0.00 to approximately 
$0.52 million per year or $0.00 to $4.4 million (present value) over a 
15-year time frame.
    Because current practice for control of drilling fluids and drill 
cuttings in the Gulf region is zero discharge and no new sources are 
projected in Cook Inlet, no additional costs will be incurred due to 
NSPS for drilling fluids and drill cuttings.
    Total compliance cost of all BAT and NSPS requirements ranges from 
$35.34 million to $40.36 million per year in 1992 $'s (or $38.3 million 
to $43.8 million annually in 1994 $'s). These compliance costs will 
also result in up to $11.5 million in lost oil and gas revenues, 
royalties and taxes annually. Note that these costs are a small 
percentage of coastal revenues and operating costs (the direct costs of 
operating the business, i.e., not including general and administrative 
costs, depletion, depreciation, taxes, interest, etc.). Total revenues 
stemming from coastal operations among coastal firms (Texas, Louisiana, 
and Cook Inlet, Alaska, only) are estimated to be $6.1 billion per 
year. Thus the total annual cost of the proposed Coastal Guidelines is 
estimated to be at most 0.7 percent of annual coastal revenues. The 
total coastal operating costs among coastal firms is estimated to be 
$1.2 billion per year, thus annual compliance costs of this proposed 
rule are estimated to be up to 3.3 percent of total annual operating 
costs.
    BAT production losses under the selected options are expected to 
total at most 40.2 million barrels of oil equivalent (BOE) over the 
lifetime of the wells and platforms as a result of the regulatory 
options (average postcompliance lifetime is 10 years in both the Gulf 
and Cook Inlet). In Cook Inlet, the production loss over the expected 
productive lifetime of the platforms is expected to be up to 12.4 
million total BOE, which is 3.1 percent of the estimated lifetime 
production for the region. In the Gulf, the lifetime production loss is 
expected to be up to 27.9 million total BOE, which is 0.9 percent of a 
high estimate of lifetime production and 1.7 percent of a low estimate 
of lifetime production in the Gulf. For the two regions combined, the 
maximum 40.2 million BOE loss (or 17.9 million BOE in present value) in 
production is 1.1 percent to 2.0 percent of total lifetime production. 
These losses are associated with declines in the net present value of 
producer income totalling up to $144.5 million in the Gulf and $15.9 
million in Cook Inlet for a total of $160.4 million or 0.7 to 1.5 
percent of total net present value of baseline producer income in the 
two regions.4 These losses result from both immediate shut in of 
wells or platforms and/or shortened economic lifetimes. A total of up 
to 111 Gulf wells (2.4 percent of all current coastal Gulf wells) and 
no Cook Inlet platforms are considered likely to shut in at once under 
the proposed options. These shut-in wells tend to be relatively low-
producing or marginal wells as can be seen from the relatively lower 
percentage of production affected as compared to a higher percentage of 
wells.

    \4\The losses of $160.4 million included costs of technology and 
resulting production losses.
---------------------------------------------------------------------------

    A maximum of 12 firms owning and/or operating Gulf Coastal wells 
might possibly fail as a result of the proposed regulatory options. 
Data were not available to rule out the possibility of firm failure, so 
they were counted as potential firm failures, thus the actual number of 
firm failures could be as few as none. No failures are predicted for 
operators in Cook Inlet. It is estimated that the majority (72 percent) 
of firms in the Gulf Coastal region by 1996 will not discharge produced 
water. Thus, most firms will incur no compliance costs. The Gulf 
Coastal firms, therefore, are potentially expected to face average 
(median) declines in equity or working capital of 0 percent. 
Discharging firms are potentially expected to face average (median) 
declines in equity and working capital of 0.37 percent and 2.63 
percent, respectively.
    The options potentially could result in a present value loss of up 
to $91 million in federal and state income tax revenues over an average 
of 10 years, or up to $13.6 million, on average, annually (primarily 
federal taxes). This loss is only 11 percent of income taxes from 
discharging wells and platforms alone. Losses to state revenues due to 
a potential loss of severance taxes total $10.8 million over 10 years, 
or $1.6 million, on average, annually. This loss is only 3.8 percent of 
severance taxes from discharging wells and platforms alone. The states 
could also potentially lose royalties totaling at most, an estimated 
present value of $39.4 million over 10 years, or $5.9 million, on 
average, annually, which is only 5.8 percent of royalties collected 
from discharging wells and platforms alone. These effects are 
negligible compared to federal and state revenues and royalties 
collected.
    The proposed rule is not expected to affect energy prices, 
international trade, or inflation, and would have a minimal impact on 
national-level employment. Primary employment losses would be 
[[Page 9464]] expected to be 181 full-time equivalents (FTEs), which is 
3.1 percent of total Gulf and Cook Inlet employment (minus baseline 
employment losses). Primary and secondary losses are expected to total 
518 FTEs. Net employment losses (including secondary effects and 
accounting for employment gains) are expected to be 121 FTEs. 
Additionally, an estimated 1,561 FTEs would be lost in the Gulf, on 
average, five years sooner (in 10 years rather than in 15 years) 
because of declines in wells' productive lifetimes. However, because 
these impacts are not felt, on average, for 10 years and because ample 
time is available for industry to adjust to declines in wells' 
productive lives through natural job attrition, these impacts are not 
considered major. This loss is equivalent to declines in total Gulf 
coastal employment averaging 3 percent per year over a 10-year period 
under the regulation, compared to declines averaging 2 percent a year 
over a 15-year period without the regulation or at most 337 FTEs on an 
equivalent first year loss basis. Table 7 summarizes the impacts 
discussed above. In Cook Inlet, platforms shut in, on average, 1 year 
earlier (in 10 years instead of 11 years). This impact is considered 
minor because ample time is still available for workers to find 
alternative employment.

  Table 7.--Summary of Economic Impacts to Gulf of Mexico and Cook Inlet Regions from the Selected BAT Options  
----------------------------------------------------------------------------------------------------------------
                    Option            Drilling waste                   TWC                                      
                    No. 4   -------------------------------------------------------                             
    Impact\1\      produced                                                               Total impacts\2\      
                    water      OPT 1      OPT 2      OPT 3      OPT 1      OPT 2                                
----------------------------------------------------------------------------------------------------------------
Number of wells                                                                                                 
 or platforms                                                                                                   
 shut in:                                                                                                       
    Wells.......        111          0          0          0          0          0  111 wells.                  
    Platforms...          0          0          0          0          0          0  0 platforms.                
Present value of       15.2          0        2.7        5.4      Negl.      Negl.  15.2 to 17.9.               
 lost production                                                                                                
 (million BOE).                                                                                                 
Total production       32.4          0        3.6        7.8      Negl.      Negl.  32.4 to 40.2.               
 lost (million                                                                                                  
 BOE).                                                                                                          
Present value of   $153,209          0       $263     $6,089      Negl.      Negl.  $153,209 to $160,409.       
 producer income                                                                                                
 lost ($000).                                                                                                   
Present value of    $84,903          0     $2,586     $7,925      Negl.      Negl.  $84,903 to $90,950.         
 federal taxes                                                                                                  
 lost ($000).                                                                                                   
Present value of    $10,676          0       $133       $272      Negl.      Negl.  $10,676 to $10,815.         
 lost severance                                                                                                 
 taxes ($000).                                                                                                  
Present value of    $34,255          0     $4,274     $9,394      Negl.  .........  $34,255 to $39,375.         
 lost royalties                                                                                                 
 to states.                                                                                                     
Total present      $283,043          0     $7,256    $23,680      Negl.      Negl.  $283,043 to $301,549.       
 value losses                                                                                                   
 ($000)\3\.                                                                                                     
----------------------------------------------------------------------------------------------------------------
\1\Impacts from selected options for other wastestreams are expected to be negligible.                          
\2\Impacts are not additive. Some double counting or undercounting of impacts occurs in the Cook Inlet analysis 
  if produced water impacts are added to drilling waste impacts. The total reflects the removal of double       
  counting, with corrections made for undercounting.                                                            
\3\Includes only dollar figures in columns. Losses comprise both compliance costs and value of lost production  
  (net operating costs). Note that these losses are not annual losses.                                          

    Based on the impacts predicted, EPA finds the costs of the proposed 
BAT limitations to be economically achievable for the Coastal Oil and 
Gas Industry.
    NSPS requirements for produced water in the Gulf (Cook Inlet NSPS 
impacts are discussed below), for drilling wastes, and for 
miscellaneous wastes are equivalent to BAT requirements. Costs for 
designing in compliance equipment are typically less than those for 
retrofitting the same compliance equipment to existing operations. 
Since new sources would most likely face costs of compliance equal to 
or less than existing operations, NSPS for Cook Inlet produced water 
are projected to pose no barriers to entry.
    NSPS for produced water in Cook Inlet are more stringent than BAT 
requirements; however, declines in net present value of production for 
existing platforms under Coastal Guidelines BAT limitations (2.4 
percent) are only negligibly less than net present value declines 
modeled for new sources under a zero discharge scenario (2.9 percent). 
Further, the modeled NSPS platform shows excellent internal rates of 
return (a measure of profitability) postcompliance, so NSPS should not 
play a major role in a decision to undertake the construction, 
development, and operation of a platform. Thus EPA finds that no 
significant barriers to entry will be created by NSPS for produced 
water in Cook Inlet and that these standards should be economically 
achievable, given the minimal impact on net present value and the 
internal rate of return.

D. Produced Water

1. BAT
    As noted earlier, this analysis of impacts associated with the 
effluent guidelines for produced water does not consider the effects of 
the Region VI General Permit for produced water. Because the Region VI 
General Permit has been promulgated as zero discharge, the costs and 
impacts of the limits on produced water in the Gulf of Mexico would be 
substantially less.
    Total production losses associated with the proposed option, Option 
#4 for produced water (zero discharge except for Cook Inlet), are 
expected to total 32.4 million BOE (or 15.2 million BOE in present 
value) over the lifetime of the wells and platforms subject to the 
rule.5 In Cook Inlet, the production loss is expected to be 4.6 
million BOE, which is 1.6 percent of the estimated lifetime production 
for the region. In the Gulf, the production loss is expected to be 27.9 
million BOE. Lifetime production in the Gulf is estimated to be 1,055 
to 3,183 million BOE (693 to 13,910 BOE in present value terms) (over a 
30-year time frame, based on a low and high estimate of decline rate in 
the region). Thus, this lost production is 0.9 to 1.7 percent of 
expected lifetime production in the Gulf. For the two regions combined, 
the lost production of 32.4 million BOE would result in a loss of 1.0 
percent to 1.7 percent of total lifetime production. These losses are 
associated with declines in the net present value of producer income 
totalling $144.5 million in the Gulf and $8.8 million in Cook Inlet for 
a total of $153.3 million (total lifetime losses). These losses result 
from both immediate shut in of wells or platforms and 
[[Page 9465]] shortened economic lifetimes. A total of 111 Gulf wells 
(2.4 percent of all current coastal Gulf wells) and no Cook Inlet 
platforms are considered likely to shut in as a result of this rule. 
These shut-in wells tend to be relatively low-producing and marginal 
wells.

    \5\Total losses calculated independently for produced water and 
drilling waste will not add exactly to the number cited above for 
combined losses because the independent estimates double count a 
very small portion of lost production in Alaska (about 1.3 percent 
of production).
---------------------------------------------------------------------------

    At most, 12 firms owning and/or operating Gulf Coastal wells (2.8 
percent of the estimated 435 Gulf Coastal region operators) might 
potentially fail as a result of the selected BAT option (i.e., data are 
not available to rule out this possibility, although the actual number 
could be as small as none). No firm failures are predicted for 
operators in Cook Inlet. The ``average'' Gulf Coastal firm does not 
discharge produced water (there are a total of 435 firms and more than 
50 percent--actually 72 percent--will not be discharging in coastal 
areas by 1996). Thus, Gulf Coastal firms are potentially expected to 
face average (median) declines in equity or working capital of 0 
percent since the majority of Gulf firms do not discharge and thus will 
not incur compliance costs. Of the 122 discharging firms, average 
(median) declines in equity or working capital of 0.37 percent or 2.63 
percent are expected to occur, respectively.
    The selected option potentially could result in a $84.9 million 
loss in federal tax revenues over an average of 10 years, or $12.6 
million, on average, annually. This loss is only 10 percent of income 
taxes collected from discharging wells and platforms alone. Losses to 
state revenues due to a potential loss of severance taxes total $10.7 
million or $1.6 million, on average, annually. This loss is only 3.8 
percent of severance taxes from dischargers alone. State royalties lost 
total $34.3 million, or $5.1 million, on average, annually. This loss 
is only 5.1 percent of royalties from dischargers alone. These effects 
are negligible compared to federal and state revenues and royalties 
collected.
    The selected option is not expected to affect energy prices, 
international trade, or inflation, and will have a minimal impact on 
national-level employment. Primary employment losses are expected to be 
181 FTEs. Primary and secondary losses are expected to total 518 FTEs. 
Net employment losses (including secondary effects and employment 
gains) are expected to be 128 FTEs. Table 8 summarizes the impacts from 
the proposed produced water option.
    Based on the minimal impacts predicted, EPA finds that the proposed 
BAT option for produced water is economically achievable for the 
Coastal Oil and Gas Industry.
2. NSPS
    This section discusses the barrier-to-entry analysis for all 
regions but Cook Inlet first, then NSPS relative to Cook Inlet is 
discussed separately. Total annual costs associated with NSPS 
requirements for produced water in the Gulf of Mexico (the only region 
where NSPS projects are of concern) are $4.5 million per year. The 
selected NSPS requirement is equivalent to BAT requirements in this 
region. Because NSPS is equivalent to BAT outside of Cook Inlet region, 
and BAT has been found to be economically achievable, NSPS requirements 
for all but Cook Inlet (which will be discussed separately below) would 
not pose a barrier to entry and are considered economically achievable.

 Table 8.--Summary of Economic Impacts to Gulf of Mexico and Cook Inlet 
              Regions From Produced Water Bat Option No. 4              
                   [Zero discharge except Cook Inlet]                   
------------------------------------------------------------------------
                                                        Option No. 4    
                      Impact                           produced water   
------------------------------------------------------------------------
Number of wells or platforms shut in..............  111 wells.          
                                                    0 platforms.        
Present value of production loss (million BOE)....  15.2.               
Total production lost (million BOE)...............  32.4.               
Net present value of producer income lost ($000)..  $153,209.           
Present value of federal taxes lost ($000)........  $84,903.            
Present value of lost severance taxes.............  $10,676.            
Present value of lost royalties to states.........  $34,255.            
Total present value losses ($000).................  $283,043.           
Employment effects................................  128 FTEs lost.      
------------------------------------------------------------------------

     Two NSPS economic models were run for Cook Inlet in the EIA for 
the Offshore Effluent Guidelines (EPA, 1993, Table 7-19; Table 7-
21).\6\ These models include a 24-slot gas/oil platform and a 12-slot 
gas platform. The gas/oil platform was estimated to incur incremental 
compliance costs for produced water disposal under a zero discharge 
requirement of $1.8 million annually (inflated to 1992 dollars). The 
key impacts affecting whether a new project would be undertaken (which 
would lead to conclusions about barriers to entry) include impacts on 
net present value (NPV) and impacts on the internal rate of return 
(IRR). The gas/oil 24 is projected to face declines in NPV of 2.9 
percent from baseline under a zero discharge requirement for produced 
water. IRR drops 5.1 percent, however, this drop is estimated to be 
from 39 percent in the baseline to 37 percent in the zero-discharge 
scenario. These impacts are not likely to affect the decision to 
undertake a project in Cook Inlet (given production levels similar to 
existing Cook Inlet platforms). Additionally, the impact on NPV from 
the zero-discharge requirement is not substantially different from the 
impacts on NPV from the proposed BAT option under the Coastal 
Guidelines at existing Cook Inlet platforms. The decline in NPV 
projected for the Coastal rule BAT option is 2.4 percent. Thus, 
existing platforms and new platforms will face similar impacts on NPV 
even though the NSPS requirement is more environmentally stringent than 
the BAT requirement.

    \6\NSPS models were run for Cook Inlet in the Offshore EIA 
because EPA considered including Cook Inlet in the offshore 
subcategory, but finally included the operations in the Coastal 
subcategory. The NSPS models constructed for the Offshore EIA were 
used as the basis for modeling the existing Cook Inlet platforms in 
the Coastal Guidelines EIA, thus comparisons between NSPS platforms 
and BAT platforms can be made.
---------------------------------------------------------------------------

    Costs and impacts associated with the Cook Inlet 12-slot platform 
are much less than those associated with the 24-slot platform or with 
existing platforms under the proposed BAT option for produced water 
under the Coastal Guidelines (see EPA, 1993, Table 7-21 and Section D.1 
of this preamble).
    Based on the analyses performed for the Offshore Guidelines (which 
continue to be relevant analyses for the Coastal Guidelines), EPA 
concludes that impacts on new sources in Cook Inlet are minimal and 
that NSPS requirements should pose no significant barriers to entry for 
two reasons: (1) declines in returns (measured as NPV and IRR) most 
likely would not affect the decision to undertake a new project since 
operations would still be quite profitable and (2) the level of impacts 
on new sources from NSPS requirements are not substantially greater 
than those on existing sources from BAT requirements.

E. Drilling Fluids and Drill Cuttings

1. BAT
    As noted above, current practice in the Gulf of Mexico region is 
zero discharge of drilling fluids and drill cuttings; and therefore, 
this proposed rule would result in no additional costs to Gulf 
operators. The three options being co-proposed affect Cook Inlet 
operations. Option 1 would result in no economic impacts. Option 2 
would cause a total 3.6 million BOE loss in production over 15 years. 
This represents a 1.2 percent reduction in the estimated lifetime 
production for the [[Page 9466]] existing platforms in Cook Inlet as 
result of three wells not being drilled. The net present value of this 
production loss (reduction in producers' net income) is $263,000 or 
less than 0.1 percent of baseline net present value. The average well 
life decreases by 0.2 years as a result of this option. Additionally, 
Federal income tax receipts would decline by $2.6 million, state income 
tax receipts by $133,000 and royalties paid to Alaska by $4.3 million.
    Option 3 would cause a production loss of 7.8 million BOE, which is 
equal to a 2.5 percent decline in the lifetime production in Cook 
Inlet. No platforms are expected to close. Federal income tax lost 
(over the life of the platforms) is estimated to decline $7.9 million 
(3.4 percent of baseline), or $1.3 million, on average, per year. No 
firm failures are predicted for operators in Cook Inlet. Total state 
severance tax revenues are predicted to decline by $0.27 million (0.5 
percent of baseline), or $0.04 million, on average, annually. Option 3 
are not expected to affect energy prices, international trade, or 
inflation, and would have a minimal impact on national-level 
employment. Employment losses are not expected. Employment gains 
(including secondary effects) are expected to be approximately 7 FTEs, 
under either Option 2 or Option 3.
     Based on the impacts predicted, EPA finds that the costs of all 
three options for drilling wastes are economically achievable for the 
Coastal Oil and Gas Industry. Table 9 summarizes the impacts from the 
proposed BAT options for drilling waste.

 Table 9.--Summary of Total Economic Impacts From Drilling Waste Option 
                                  No. 3                                 
------------------------------------------------------------------------
                               Option No. 3 drilling waste              
     Impact     --------------------------------------------------------
                   Opt 1            Opt 2                  Opt 3        
------------------------------------------------------------------------
Number of Wells                                                         
 or platforms                                                           
 shut in:                                                               
    Wells......          0  0....................  0.                   
    Platforms..          0  0....................  0.                   
Present value            0  2.7..................  5.4.                 
 of total                                                               
 production                                                             
 lost (million                                                          
 BOE).                                                                  
Total                    0  3.6..................  7.8.                 
 production                                                             
 lost (million                                                          
 BOE).                                                                  
Net present              0  $263.................  $6,089.              
 value of                                                               
 producer                                                               
 income lost                                                            
 ($000).                                                                
Present value            0  $2,586...............  $7,925.              
 of federal                                                             
 taxes lost                                                             
 ($000).                                                                
Present value            0  $133.................  272.                 
 of lost                                                                
 severance                                                              
 taxes ($000).                                                          
Present value            0  $4,274...............  $9,394.              
 of lost                                                                
 royalties to                                                           
 states.                                                                
Total present            0  $7,256...............  $23,680.             
 value losses                                                           
 ($000).                                                                
Employment               0  7 FTEs gained........  7 FTEs gained.       
 effects.                                                               
------------------------------------------------------------------------

2. NSPS
    The same options are being considered for NSPS as were for BAT. 
Thus, both new platforms and existing platforms face the same 
requirements. Since costs for new operations to design in compliance 
equipment should be as expensive as or less expensive than those for 
existing operations to retrofit the same compliance equipment, no 
significant barriers to entry are predicted to exist. Furthermore, 
since BAT was found to be economically achievable, NSPS is considered 
economically achievable.
F. Treatment, Workover, and Completion Fluids

1. BAT
    No costs are incurred for Option 1. Costs of disposing of 
treatment, workover, and completion fluids under Option 2 are 
approximately $610,000 annually for all Gulf wells estimated to 
discharge treatment, workover, and completion fluids. A typical Gulf 
Coast well produces an average of 36 barrels of oil per day according 
to the 1993 Coastal Oil and Gas Questionnaire. At $18 per barrel, total 
annual production revenue at a typical well is estimated to be 
$237,000. Treatment, workover, and completion fluids disposal costs are 
estimated to be 0.74 percent of annual production revenues at a typical 
Gulf Coastal well, and no major impacts are expected as a result of 
either of the selected option (refer to Table 6). For this reason, EPA 
finds that the costs of Option 2 for treatment, workover, and 
completion fluids should be economically achievable for the Coastal Oil 
and Gas Industry.
2. NSPS
    The options considered for NSPS for treatment, workover, and 
completion fluids are the same as those for BAT. Because NSPS is 
equivalent to BAT in the Gulf, new operations face the same or lower 
costs as existing operations. Thus, treatment, workover and completion 
fluids disposal costs for Option 2 will be 0.7 percent or less of 
annual production revenues at a typical Gulf coastal well. In Cook 
Inlet, there are no costs for zero discharge of this wastestream 
because this wastestream is commingled with produced water, and thus, 
the cost has already been accounted for in costing zero discharge for 
produced water. Option 2 NSPS requirements will not pose a significant 
barrier to entry. Furthermore, since BAT in the Gulf and NSPS in Cook 
Inlet is economically achievable, NSPS is economically achievable.

G. Cost-Effectiveness Analysis

    In addition to the foregoing analyses, EPA has performed a cost-
effectiveness analysis for the selected options for produced water; 
treatment, workover, and completion fluids; and drilling wastes. 
According to EPA's standard procedures for calculating cost-
effectiveness, all the options considered for each waste stream have 
been ranked in order of increasing pounds-equivalent (PE) removed (see 
the introduction to this section for a discussion of pounds-equivalent, 
a methodology for putting pollutants of differing toxicity on a 
comparable basis.) Cost-effectiveness is calculated as the ratio of the 
incremental annual costs to the incremental pounds-equivalent removed 
under each option. So that comparisons of the cost-effectiveness among 
regulated industries can be made, annual costs for all cost-
effectiveness analyses are reported in 1981 dollars.
    In 1981 dollars, the incremental cost-effectiveness for the 
selected options are:

--$3/PE for produced water
--$0/PE for Option 1, $769/PE for Option 2 and $292/PE for Option 3 for 
drilling wastes
--$0/PE for Option 1 and $200/PE for Option 2 for treatment, workover, 
and completion fluids

H. Regulatory Flexibility

    All of the firms expected to fail (0 to 12 firms) as a result of 
the proposed rule [[Page 9467]] are small entities (i.e., they employ 
fewer than 500 employees), however, nearly all the firms operating in 
the Coastal region are small (approximately 372 out of an estimated 435 
firms, or 86 percent are small firms). Thus 0 percent to 3 percent of 
small firms could potentially fail as a result of this rule. The high 
end of this estimate is very conservative because these firms might not 
fail; however, but data were unavailable to rule out the possibility. 
Thus these firms were considered to have the potential to fail as a 
result of the proposed rule. Due to data constraints, a cash flow 
analysis was not undertaken, but potential effects on working capital 
and equity were analyzed. In general, the average small firm that is 
currently discharging produced water or other wastes will experience a 
somewhat greater decline in working capital or equity than that for 
large firms. Among small dischargers, the median change in equity is 
1.26 percent as compared with 0.02 percent for large firms, and the 
change in working capital is 4.54 percent, versus 0.05 percent for 
large firms. However, the typical small discharging firm will not 
experience a change in equity or working capital of more than 5 
percent. Additionally most small firms are currently not discharging 
any wastes, thus will experience no change in equity or working 
capital. When these nondischarging firms are also considered, the 
median small firm operating in the coastal region will experience no 
change in equity or working capital. Thus EPA does not find that 
impacts on small firms will be disproportionately greater than those on 
large firms.

VIII. Non Water Quality Environmental Impacts

    The elimination or reduction of one form of pollution has the 
potential to aggravate other environmental problems. Under sections 
304(b) and 306 of the CWA, EPA is required to consider these non-water 
quality environmental impacts (including energy requirements) in 
developing effluent limitations guidelines and NSPS. In compliance with 
these provisions, EPA has evaluated the effect of these regulations on 
air pollution, solid waste generation and management, consumptive water 
use, and energy consumption. Because the technology basis for the 
limitation on drilling fluids and drill cuttings may require 
transporting the wastes to shore for treatment and/or disposal, 
adequate onshore disposal capacity for this waste is critical in 
assessing the options. Safety, and impacts of marine traffic on coastal 
waterways, were other factors also considered. EPA evaluated the non-
water quality environmental impacts on a regional basis because the 
different regions each have their own unique considerations.

A. Drilling Fluids and Cuttings

    The control technology basis for compliance with the options 
considered for the drilling fluids and drill cuttings wastestreams is a 
combination of product substitution, grinding followed by injection, 
and/or transportation of drilling wastes to shore for treatment and/or 
disposal. The non-water quality environmental impacts associated with 
the treatment and control of these wastes are summarized in Table 10. 
These non-water quality environmental impacts are those associated with 
drilling fluids and cuttings disposal and treatment alternatives only 
in Cook Inlet. All other coastal areas are currently achieving zero 
discharge of these wastes and, thus the control options cause no 
additional impacts. Non-water quality environmental impacts estimates 
are presented in more detail in the Coastal Technical Development 
Document.

                     Table 10.--Non-Water Quality Impacts for Drilling Waste Control Options                    
----------------------------------------------------------------------------------------------------------------
                                                     Volume of                                                  
                                                       waste         Volume of                         Fuel     
                     Options                      transported to    ground and     Air emissions   requirements 
                                                      onshore     injected waste     (tons/yr)     (BOE)\2\/year
                                                    disposal\3\       (bbls)                                    
----------------------------------------------------------------------------------------------------------------
Option 1: Zero for all except BPT for Cook                                                                      
 Inlet\1\.......................................               0               0               0               0
Option 2: Zero for all except for Cook Inlet                                                                    
 with more stringent toxicity limit.............          93,984               0               9           1,700
Option 3: Zero for all..........................         422,780         130,066            12.5          2,300 
----------------------------------------------------------------------------------------------------------------
\1\Option one represents current standards such that no additional barrels of wastes or resulting air emissions 
  or fuel requirements are required.                                                                            
\2\BOE (barrels of oil equivalents).                                                                            
\3\The volume of barged waste does not include wastes that would be ground and injected. The air emissions and  
  fuel requirements presented in this table are a result of transporting these barged wastes and for grinding   
  and injecting the rest.                                                                                       

1. Energy Requirements
    Energy requirements for Options 2 and 3 were calculated by 
identifying those activities necessary to support onshore disposal of 
drilling wastes and injection at the platform. The only landfill 
available for disposal of drilling wastes in Cook Inlet is privately 
owned and operated. Access to this landfill is limited to only the two 
operators that own and operate it. The landfill, which is located on 
the west side of Cook Inlet, is only operated for four months in the 
summer because of climate conditions that are specific to Cook Inlet. 
Drilling wastes are first transported by supply boats from the platform 
to a temporary storage facility on the east side of Cook Inlet to be 
unloaded and temporarily stored. Barges are used to transport drilling 
wastes from the east to the west side of Cook Inlet. Trucks are then 
used to transport the muds and cuttings to the landfill. For the other 
operators in Cook Inlet, the technology basis for Option 3 (zero 
discharge) is grinding followed by injection at the platform. For 
Option 2 (which includes a 100,000 ppm (SPP) to 1,000,000 ppm (SPP) 
toxicity limitation that all operators would not be able to meet), the 
technology basis would be transportation and disposal to the lower 
contiguous United States for those operators not having access to 
Alaska landfills Option 2.
    EPA used the volumes of drilling waste requiring onshore disposal 
to estimate the number of supply boat trips necessary to haul the waste 
to shore. Projections made regarding boat use included types of boats 
used for waste transport, the distance travelled by the boats, 
allowances for maneuvering, idling and loading operations at the drill 
site, and import activities at the marine transfer station. EPA 
estimated fuel required to operate the cranes at the drill site and 
import based on projections of crane usage. EPA determined crane usage 
by considering the drilling waste volumes to be handled and estimates 
of crane handling capacity. EPA also used drilling waste 
[[Page 9468]] volumes to determine the number of truck trips required. 
The number of truck trips, in conjunction with the distance travelled 
between the marine transfer station and the disposal site, enabled an 
estimate of fuel usage. The use of land-spreading equipment at the 
disposal site was based on the drilling waste volumes and the projected 
capacity of the equipment. In evaluating the zero discharge 
requirement, EPA calculated for those operators that do not have access 
to the landfill in Cook Inlet, fuel requirements for grinding and 
injection equipment. The equipment evaluated included the pumps running 
the cuttings grinding system (the ball mills and conveyors) and the 
injection pumps. The methodology used to determine fuel consumption is 
further discussed in the Coastal Technical Development Document. Table 
9 summarizes the incremental increase in energy requirements for the 
drilling fluids and drill cuttings options considered for this rule.
2. Air Emissions
    EPA estimated air emissions resulting from the grinding and 
injection equipment systems, or the operation of boats, cranes, trucks 
and earth-moving equipment necessary to either dispose of drilling 
fluids and drill cuttings onshore or to grind and inject these wastes 
by using emission factors relating the production of air pollutants to 
time of equipment operation and amount of fuel consumed. The 
incremental increase in air emissions associated with the control 
options considered by EPA in this final rulemaking are presented in 
Table 9.
    In developing regulations to control air pollution from OCS sources 
pursuant to the 1990 Clean Air Act Amendments, the EPA Office of Air 
Quality Planning and Standards estimated the air emissions associated 
with various stages of oil/gas resource development activities 
(``Control Costs Associated With Air Emission Regulations For OCS 
Facilities,'' Final Report September 30, 1991. Prepared by Mathtech, 
Inc. for EPA). In this study, EPA estimated levels of both controlled 
and uncontrolled emissions from exploration, development, and 
production operations. Information from this study was used to 
determine emissions from coastal operations independent of this rule. 
Nitrogen oxides (NOX) emissions from exploratory drilling 
activities were estimated at 78 tons/operation. For comparison, the 
zero discharge requirement for all drilling activities in the Cook 
Inlet projected over the next seven years from scheduled promulgation 
is estimated at approximately 54 tons of NOX for each well subject 
to the zero discharge limitations.
3. Solid Waste Generation and Management
    The regulatory options considered for this rule will not cause 
generation of additional solids as a result of the treatment 
technology. However, as already discussed, spent drilling fluids and 
drill cuttings may be disposed of onshore to comply with these options.
    There are currently no commercially operating disposal sites in 
Cook Inlet accepting drilling wastes. The only land disposal facility 
accepting drilling wastes from Cook Inlet operations is privately owned 
and operated. The lack of commercial disposal sites would require 
operators that do not own a land disposal facility to either transport 
the drilling wastes to the nearest known commercial disposal facility 
located in Idaho or inject the drilling wastes into underground 
formations.
    Capacity estimates for the only available disposal facility in Cook 
Inlet show that this landfill has enough storage capacity to accept the 
volume of drilling fluids and cuttings (422,780 bbls over the next 
seven years following promulgation of this rule) that would be 
generated under Option 3 (zero discharge) from the two operators that 
it now serves. The volume of drilling wastes generated by these two 
operators under the zero discharge option represents about 71 percent 
of the excess available capacity at this landfill. The other Cook Inlet 
operators would not dispose of their drilling fluids and cuttings by 
landfilling, but rather by grinding and injection (See Section VI), 
which does not require land disposal.
    Under Option 2, the estimated volume of drilling fluids and 
cuttings requiring land disposal is estimated to be approximately 17 
percent of the total wastes generated over the next seven years 
following promulgation of this rule (or 17 percent of 552,846 bbls 
which is approximately to 94,000 bbls). This is based on the estimate 
of 83 percent compliance with a toxicity limitation between 100,000 ppm 
(SPP) and 1,000,000 ppm (SPP). EPA estimates that the two operators 
having access to the Cook Inlet landfill will send their portion of 
these wastes there (amounting to approximately 72,000 bbls), and as 
shown above, there would be sufficient landfill capacity to accommodate 
this as well as the zero discharge option. The other three operators 
not having access to the Cook Inlet landfill would most likely dispose 
of their drilling fluids and cuttings for this option (amounting to 
approximately 22,000 bbls) in a landfill available in Idaho, rather 
than grind and inject them (See Section VI), because this is less 
expensive than installing grinding and injection equipment for these 
smaller volumes. Because of this small volume of wastes, EPA assumed 
that there is ample landfill capacity in the lower 48 states for 
disposal of 22,000 bbls of wastes that would be generated over the 
seven years following the scheduled promulgation.

4. Consumptive Water Use

    Since little or no additional water is required above that of usual 
consumption, no consumptive water loss is expected as a result of this 
rule.
5. Safety
    EPA investigated the possibility of an increase in injuries and 
fatalities that would occur as a result of hauling additional volumes 
of drilling wastes to shore. EPA acknowledges that safety concerns 
always exist at oil and gas facilities, regardless of whether pollution 
control is required. EPA believes that the appropriate response to 
these concerns is adequate worker safety training and procedures as is 
practiced as part of the normal and proper operation of oil and gas 
facilities.
6. Increased Vessel Traffic in Cook Inlet
    EPA estimates that a total of 231 boat trips would be required to 
comply with a zero discharge requirement. This estimate is for all 
drilling that will take place in the next seven years after expected 
promulgation of the rule. In actuality, EPA determined, from drilling 
schedules supplied by industry, that drilling would only occur for 
seven years after promulgation. Thus, these 231 boat trips equate to 
approximately 33 additional boat trips per year for seven years. EPA 
does not expect this to cause traffic problems in the Inlet. In fact, 
it will serve to provide service companies with additional work. EPA 
has calculated expected job gains associated with the manufacture, 
installation and operation of technologies required to comply with this 
rulemaking.
    However, job gains could also be realized due to increased boat 
trips and related work required of service companies. These job gain 
estimates have not been quantified.

B. Produced Water

    In assessing the non-water quality environmental impacts of the 
options considered for control of produced water, EPA projected the 
incremental increase in energy requirements and air 
[[Page 9469]] emissions associated with the regulatory options 
considered. These non-water quality environmental impacts are presented 
in Table 11.

  Table 11.--Non-Water Quality Environmental Impacts for Produced Water 
------------------------------------------------------------------------
                          Fuel requirements (BOE/ Total emissions (tons/
                                    yr)                     yr)         
         Option          -----------------------------------------------
                              BAT       NSPS\1\       BAT       NSPS\1\ 
------------------------------------------------------------------------
1. BPT All..............           0           0           0           0
2. Oil and Grease.......      28,595       1,712         258          17
3. Zero Discharge; Cook                                                 
 Inlet BPT 48/72........     258,946       5,948       2,799          64
4. Zero Discharge; Cook                                                 
 Inlet Oil and Grease...     260,376       5,948       2,801          64
5. Zero Discharge All...     343,759       5,948       2,899          64
------------------------------------------------------------------------
\1\Impacts are associated only with new sources in the Gulf of Mexico.  
  No new sources are expected in other coastal areas.                   

    For small volume production facilities in the Gulf, produced water 
would be transported to commercial facilities for injection to comply 
with the options based on either gas flotation or injection because it 
is less expensive for smaller flows than installing injection or gas 
flotation equipment on-site. Produced water transportation (via barge 
or truck), and vacuum pumps to unload produced water at the commercial 
facilities are sources included in fuel use and air emissions 
calculations. For medium to large volume facilities in the Gulf and in 
Cook Inlet, either gas flotation or injection would be the technology 
bases to comply with the options. EPA determined the fuel requirements 
and air emissions for these technologies by evaluating:
     Power requirements to operate feed pumps and gas flotation 
devices
     Injection pumps and feed pumps for injection and 
pretreatment technology
    Energy consumption for the different options was determined based 
on the produced water flowrates and the associated power requirements 
for operating treatment and injection systems.
    EPA calculated the air emissions for each discharging facility by 
taking the product of specific emission factors, the usage in hours 
(that is, hours per year), and the horsepower requirements. EPA 
calculated total emissions for zero discharge based on the use of 
reciprocating natural gas fired engines as the power source for the 
injection pumps. According to industry, these engines are commonly used 
in coastal production facilities. Air emissions increases calculated 
for the produced water options include nitrogen oxides (NOX), 
sulfur dioxide (SO2), and hydrocarbons. See the Coastal Technical 
Development Document for more detail on the estimated compliance costs 
and EPA's calculation of pollutant removals and non-water quality 
environmental impacts.
     The only increase in vessel waterway traffic due to these options 
would be for the small facilities that would be required to barge their 
produced waters to a commercial facility. This amounts to approximately 
50 facilities out of a total of 216. Because vessels generally service 
several facilities on any given trip, EPA expects this increase to be 
small enough that it will be absorbed into current vessel operations. 
Additionally, use of the coastal waterways by the oil and gas industry 
accounts for less than 10 percent of all commercial traffic according 
to data from the Minerals Management Service. A slight increase in 
vessel traffic due to this rule would have negligible effect on the 
water traffic overall.
 C. Treatment, Workover and Completion Fluids

    The non-water quality environmental impacts associated with 
disposal of treatment, workover and completion fluids are the fuel 
requirements and air emissions resulting from transportation to 
commercial disposal where operators choose this method to comply with 
the rule. No incremental energy requirements and air emissions have 
been estimated for existing facilities that treat and discharge or 
inject treatment, workover and completion fluids onsite. This is 
because the control options for the facilities that treat and inject 
onsite are based on commingling treatment, workover and completion 
fluids with the produced water and, therefore, non-water quality 
environmental impacts associated with this activity have already been 
taken into account in assessing the impacts of control options for 
produced water.
    Option 1, requiring BPT limits and zero discharge to freshwaters in 
Louisiana, would not cause additional non-water quality impacts because 
it reflects current practice (zero discharge of these fluids is a 
requirement in the Region VI general drilling permit).
    Option 2, requiring limitations equal to those for produced water, 
would result in the consumption of approximately 1000 and 300 
additional BOE per year, for BAT and NSPS respectively, and the 
generation of 12 and 3 tons of additional emissions per year for BAT 
and NSPS respectively.

IX. Executive Order 12866

    Under Executive Order 12866, (58 FR 51735; October 4, 1993) the EPA 
must determine whether the regulatory action is ``significant'' and 
therefore subject to OMB review and the requirements of the Executive 
Order. The Order defines ``significant regulatory action'' as one that 
is likely to result in a rule that may:
    (1) Have an annual effect on the economy of $100 million or more or 
adversely affect in a material way the economy, a sector of the 
economy, productivity, competition, jobs, the environment, public 
health or safety, or State, local or tribal governments or communities;
     (2) Create a serious inconsistency or otherwise interfere with an 
action taken or planned by another agency;
     (3) Materially alter the budgetary impact of entitlements, grants, 
user fees, or loan programs or the rights and obligations of recipients 
thereof; or
     (4) Raise novel legal or policy issues arising out of legal 
mandates, the President's priorities, or the principles set forth in 
the Executive Order.
     Pursuant to the terms of Executive Order 12866, it has been 
determined that this rule is a ``significant'' regulatory action. As 
such, this action was submitted to OMB for review. Changes made in 
response to OMB suggestions or recommendation will be documented in the 
public record for this rulemaking. [[Page 9470]] 

X. Executive Order 12875

     Executive Order No. 12875 requires Federal Agencies to consider 
the impacts that unfunded mandates will have on state, local, or tribal 
governments. The coastal oil and gas industry is not associated with 
tribal governments, and the burden to state and local regulatory 
authorities is expected to be minimal, if not decreased, by the 
implementation of this rule.
    The CWA, section 301 prohibits discharges of pollutants unless 
permitted under sections 402 or 404 of the CWA. Effluent limitations 
guidelines, new source performance standards and pretreatment standards 
are implemented through the National Pollutant Discharge Elimination 
System (NPDES) permits issued under section 402 of the CWA by EPA's 
Regions or, if delegated NPDES authority, the delegated states. 
Generally, coastal oil and gas facilities are permitted by EPA Regions, 
or in the case of Alabama, by the Alabama NPDES program, using general 
permits which cover an entire area specified in that permit. For 
example, Region VI's general permit for coastal drilling operations 
covers all coastal operations in Texas and Louisiana, except for a few 
facilities whose operations are noted in the permit. Alabama currently 
requires zero discharge in their permits for coastal oil and gas 
operations.
    These proposed requirements, when promulgated, will be implemented 
via the existing regulatory structure and no additional burden is 
expected. In the absence of effluent limitations guidelines, 
establishing BAT, BCT, NSPS, PSES and PSNS, permit limitations are to 
be developed on as case-by-case ``Best Professional Judgement'' (BPJ) 
basis. In addition, all NPDES permits must incorporate state water 
quality standards. Once, these Coastal Guidelines are in place, the 
Regions will no longer be required to expend both in-house and 
contractor efforts in BPJ developments, and where zero discharge is 
required, the Regions and states will no longer be required to 
determine permit limitations based on water quality standards. Thus, 
these guidelines will actually serve to reduce the regulatory burden on 
the Regions and states that permit existing sources in the coastal oil 
and gas industry. As it could take approximately $100,000 for 
contractor support, and at least one in-house FTE per general permit 
development based on BPJ and water quality requirements, this could 
result in substantial savings. However, issuance of NSPS creates a 
class of facilities that is regulated as new sources which may need to 
be permitted by the regions and states. Because the number of new 
sources is projected to be very small and can be permitted by general 
permits, we expect this to be a minimal resource requirement.
    Since the inception of the project in 1994, there have been 
periodic meetings with the industry and several trade associations, 
including the Louisiana and Texas Independent Oil and Gas Associations 
(TIOGA and LIOGA) and American Petroleum Institute (API) to discuss 
progress on the rulemaking. The Agency also has met with the Natural 
Resources Defense Council (NRDC) to discuss progress on this 
rulemaking. Because all of the facilities affected by this proposal are 
direct dischargers, the Agency did not conduct an outreach survey of 
POTWs.
    The Agency also held a public meeting on July 19, 1994. The purpose 
of the meeting was to present the project status and discuss the 
technical options under consideration for this proposal. 
Representatives from industry trade associations, individual industry 
companies, state regulatory authorities the U.S. Department of Energy 
and Interior (Minerals Management Service) and the Sierra Club Legal 
Defense Fund attended.
    The Agency will continue this process of consulting with state, 
local, and other affected parties after proposal in order to further 
minimize the potential for unfunded mandates that may result from this 
rule.

XI. Paperwork Reduction Act
    The proposed coastal oil and gas effluent limitations guidelines 
and standards contain no new information collection activities, and 
therefore, no information collection request will be submitted to OMB 
for review in compliance with the Paperwork Reduction Act, 44 U.S.C. 
3501 et seq.

XII. Environmental Benefits Analysis

A. Introduction

    The Water Quality Benefit Analysis (Benefit Analysis) evaluates the 
effect of current discharges and the benefits of proposed limitations 
for the coastal subcategory of the oil and gas extraction industry on 
the coastal environment. The benefit analysis considers two separate 
geographic areas: Gulf of Mexico (Louisiana and Texas) and Cook Inlet, 
Alaska. The benefit analysis examines potential impacts from current 
produced water discharges in both geographic areas, and from drilling 
fluids and drill cuttings discharges in Cook Inlet. Effect of drilling 
fluids and drill cutting discharges are not evaluated for Gulf of 
Mexico coastal operations since they are prohibited by state 
authorities and existing NPDES permits. Three types of benefits are 
analyzed: quantified and non-monetized, quantified and monetized, and 
non-quantified and non-monetized benefits.
    Coastal waters maintain diverse ecosystems which act as spawning 
grounds, nurseries and habitats for important estuarine and marine 
species (finfish and shellfish); support highly valuable commercial and 
recreational fisheries; and provide critical habitat for seabirds, 
shore birds and terrestrial wildlife. The commercial fisheries in Texas 
and Louisiana (finfish, shrimp, crabs and oysters) were valued at $476 
million in 1992. Commercial species spend a significant portion of 
their life cycle in bays and estuaries. The 1993 value of Cook Inlet 
commercial fisheries (finfish, clams,crabs and shrimp) was $48 million. 
Approximately $30 million of this total was from Upper Cook Inlet 
salmon fisheries. The estimated consumer surplus associated with Cook 
Inlet recreational fisheries is about $26 million per year (in 1993 
dollars). In addition, personal use and subsistence fisheries provide 
food source and cultural values to Alaskan residents and Alaskan native 
populations. Coastal waters also serve as critical habitats for 
numerous federally designated endangered and threatened species 
(including 32 in coastal areas of Texas and Louisiana) , and migrating 
waterfowl.
    Coastal waters are generally shallow, where tidal action has 
limited effect, and dilution and dispersion are more limited than 
offshore waters. Additionally, pollutants can migrate much more readily 
into sediments, where they may have long residence times. Consequently, 
these receiving environments are highly sensitive to pollutant 
discharges compared to open offshore areas. Many of the pollutants in 
coastal oil and gas discharges are either conventional pollutants, 
aquatic toxicants, human carcinogens, or human systemic toxicants. The 
impact of these pollutants on aquatic biota include acute toxicity; 
chronic toxicity; effects on reproductive functions; physical 
destruction of spawning and feeding habitats; and loss of prey 
organisms. In addition, many of these pollutants are persistent, 
resistant to biodegradation and accumulate in aquatic organisms. 
Chemical contamination of aquatic biota may also directly or indirectly 
impact local aquatic and terrestrial wildlife and humans consuming 
exposed biota. [[Page 9471]] 
    Conventional pollutants, such as TSS and oil & grease can have 
adverse effects on human health and environment. For example, habitat 
degradation can result from increased suspended particulate matter that 
reduces light penetration and thus primary productivity. Suspended 
solids in the water column can have a direct effect on the fish either 
killing them, or reducing their growth rate and/or resistance to 
disease, preventing successful development of fish eggs and larvae, 
modifying fish movement and migration and reducing the abundance of 
food available to fish. Settleable materials which blanket the bottom 
of the water bodies cause benthic smothering, damage invertebrate 
populations and can alter spawning grounds and feeding habitat. Oil and 
grease can have lethal effect on fish, by coating surface gills causing 
asphyxia, or depleting oxygen levels due to excessive biological 
demand, or reducing reaeration because of surface film. Oil and grease 
can also have detrimental effects on waterfowl by destroying the 
buoyancy and insulation of their feathers. Bioaccumulation of oil 
substances can cause human health problems including tainting of fish 
and bioaccumulation of carcinogenic polycyclic aromatic compounds.
    Benefits of this proposed rule include elimination of toxic, 
conventional, and nonconventional pollutants, or reduction to levels 
below those considered to impact receiving water's biota, and 
elimination or reduced impacts on human health. Potential benefits may 
ultimately include reduced aquatic habitat degradation; improved 
recreational fisheries; improved subsistence and personal use fisheries 
(important to low-income anglers and Alaska's Native anglers, etc.); 
improved commercial fisheries; improved aesthetic quality of waters; 
improved recreational opportunities; and decreased harm to threatened 
or endangered species in Gulf of Mexico and Cook Inlet.
B. Quantitative Estimate of Benefits

    (1) Gulf of Mexico. The Gulf of Mexico benefits associated with 
produced water include: (a) 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 its discharge 
into coastal waters in the Gulf of Mexico; (ii) modeled water quality 
benefits expressed as reduction/elimination in exceedances of human 
health or aquatic life state water quality standards; and (iii) 
estimated reduction of total point source toxic loading contribution to 
Texas and Louisiana estuarine drainage systems, and (b) monetized 
benefits (i.e., (i) estimated reduction of carcinogenic risk from 
consumption of seafood contaminated with Ra226 and Ra228 
based on limited observations and modeled levels; and (ii) estimated 
ecological benefits of zero discharge of produced water.))
    (a) Quantified Non-Monetized Benefits.
    (i) Documented Case Studies. A comprehensive review of available 
data identified 25 study sites (12 in Louisiana and 13 in Texas) that 
examined impacts of produced water discharges on coastal environment. 
The majority of evaluated study sites are in water depths less than 3 
meters, and include variable environments (i.e., wetlands, saltmarshes, 
and fresh or brackish marshes), and both relatively low and high energy 
areas. The documented impacts show elevated hydrocarbons and metals in 
water column and sediments, and reveal impacts on biota (i.e., 
depressed community structure such as abundance or diversity) up to 
1,000 meters (and more) from the produced water discharge. The salinity 
effects are typically detected up to 300 meters from the discharge, and 
up to 800 meters in dead-end canals. A benthic dead zone (no benthic 
fauna) is documented up to 15 meters and severely depressed benthic 
communities are noted to 150 to 400 meters from produced water 
outfalls.
    (ii) Projected Water Quality Benefits. The effects of toxic 
pollutants in current (BPT) produced water discharges on receiving 
water quality and benefits of proposed effluent guidelines are 
evaluated. Plume dispersion modeling is performed to project in-stream 
concentrations of 66 pollutants (representing subcategory-wide produced 
water discharge) at the edge of the state-prescribed mixing zones for 
Texas and Louisiana at one and three meters water depths. The in-stream 
concentrations are compared to Texas and Louisiana state standards; 
Texas has standards for 12 of the pollutants and Louisiana for 14. The 
results based on the mean discharge rate show one pollutant (silver) in 
Texas exceeds its chronic standard at the one meter depth; in 
Louisiana, one pollutant (copper) exceeds two acute standards (daily 
average and maximum), two pollutants (copper and lead) exceed two 
chronic standards, and one pollutant (benzene) exceeds two human health 
standards at the one meter depth, and at three meter depth one 
pollutant (copper) exceeds its acute standard, and one pollutant 
(benzene) exceeds two human health standards at the three meter depth. 
The proposed BAT zero discharge option would eliminate all projected 
exceedances.
    (iii) Projected Reduction of Point Source Toxic Loading 
Contribution to Texas and Louisiana Estuarine Drainage Systems. The 
watershed pollutant loadings from produced water are compared to other 
industrial and municipal point sources (i.e., excluding pollutant 
loadings from nonpoint sources and atmospheric deposition) for Texas 
and Louisiana estuarine drainage systems. At the current (BPT) 
discharge level, produced water in Texas contributes about 20 percent, 
and in Louisiana about 60 percent of total point source mass pollutant 
loadings into their respective watersheds. The proposed zero discharge 
would eliminate produced water pollutant loading contribution to the 
Texas and Louisiana coastal watershed.
    (b) Quantified Monetized Benefits. (i) Projected Cancer Risk 
Reduction Benefits. Upper bound individual cancer risks from consuming 
fish contaminated with Ra226 and Ra228 from current produced 
water discharges are estimated for recreational and subsistence 
anglers, and aggregate human cancer risks are projected and monetized. 
Risks are estimated using two types of data: (1) Measured field seafood 
data (i.e., because background levels could not be adequately 
determined average Ra\226\ and Ra\228\ levels were used based on field 
samples of fish, crabs and oysters collected within 3,000 meters of 
produced water discharges in coastal subcategory areas of Louisiana), 
and (2) modelled effluent data (i.e., using current subcategory-wide 
produced water concentrations of Ra\226\ and Ra\228\ and plume 
dispersion model at mean outfall discharge rates to estimate Ra\226\ 
and Ra\228\ levels in seafood). [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 some of 
which are not contaminated with the Ra\226\ and Ra\228\ in coastal 
produced water discharges. Projected individual cancer risks for both 
risk assessment approaches are at 10-4 level for subsistence 
anglers, and at 10-6 level recreational anglers. The proposed zero 
discharge of produced water will eliminate these estimated cancer risks 
over time. Based on measured field data, the proposed BAT is projected 
to [[Page 9472]] eliminate 1.1 to 4.3 annual cancer cases and the 
monetized benefits from cancer cases avoidance are projected to range 
from $2.3 to $43 million. Using the modelling approach, the proposed 
BAT is projected to eliminate 1.2 to 4.6 cancer cases per year, 
resulting in monetized benefits in $ 2.4 to $46 million per year.
    The temporal dynamics of both impacts and benefits assessments is 
relevant to the human health risk assessment. For the assessments of 
cancer reduction benefits, the methodology is consistent with 
estimating costs for the rule, using a one-year ``snap-shot'' approach. 
Allocating the full value of annual benefits within one year following 
cessation of produced water discharges may appear to over-estimate 
potential annual benefits in cases where incomplete recovery has 
occurred. However, in such cases where impacts are incompletely 
recovered, a consideration of total impact would need to include any 
impacts expected to occur beyond that year. This analysis does not 
attempt to identify or allocate benefits on a yearly basis, but merely 
averages total benefits so that monetized benefits may be compared to 
costs that are developed using the same approach.
    (ii) Projected Ecological Benefits for Texas and Louisiana Bays. A 
potential ecological benefit of zero discharge of produced water in 
Texas and Louisiana coastal areas is projected from a Trinity Bay case 
study. This study shows that measures of total benthic abundance and 
species richness are depressed by discharges, up to distances between 
1.7 kilometers and 4 kilometers from the point of discharge. (Data on 
abundance of other species, such as waterfowl were not collected.) 
Taking into account the severity of these impacts at different 
distances, the equivalent acreage affected in this case study ranges 
from 200 to 2,817 acres. Extrapolating from this case study to the 
other sites that would be affected by this rule, EPA estimates that the 
total Texas and Louisiana acreage affected ranges from 14,607 acres to 
195,488 acres. EPA identified numerous values for an acre of wetland 
but none were marginal estimates for Texas or Louisiana, and some did 
not net out the cost of recreational use. A literature review for 
wetland value estimates conducted for Mineral Management Services (MMS) 
in 1991, reports that different studies have estimated recreational and 
commercial wetland values for coastal Louisiana ranging from $57 to 
$940 per acre per year (with a median value of $410 per acre per year) 
in 1990 dollars. Using this range of values, the estimated increase of 
Texas and Louisiana Bay recreational values ranges from $0.8 million to 
$184 million per year in 1990 dollars ($1.0 million to $210 million in 
1994 dollars). These per acre estimates are consistent with the 
estimated average recreational value of the acreage of Galveston Bay, 
which ranges from $336 to $730 per acre. (The Galveston Bay estimates 
do not net out the cost to recreational users of using the resource.) 
These estimates may not be marginal values as they are calculated from 
the total recreational value of Galveston Bay and total acreage of the 
Bay. There may be concern that the value of wetland recovery diminishes 
as the amount of recovered acreage increases and therefore these 
average values would overstate the relevant marginal values by an 
unknown amount. As these studies use different estimation methods, 
cover different types of wetlands, marshes and coastal waters which may 
differ from those affected by this rule, and generally reflect average 
values rather than the social valuation of small (marginal) changes in 
acreage, EPA solicits comments on the appropriateness of this benefit 
analysis and requests data on marginal values of wetlands, in 
particular in Texas and Louisiana.
    (iii) Total Monetized Benefits. EPA estimates that total monetized 
benefits (i.e. combining cancer risk reduction and ecological benefits) 
resulting from proposed zero discharge of produced water range from 
approximately $3.2 to $230 million per year in 1990 dollars ($3.7 
million to $263 million in 1994 dollars).
    (2) Cook Inlet. Quantified benefits analyzed in Cook Inlet include 
non-monetized quantified benefits associated with proposed regulations 
of produced water and drilling fluids and drill cuttings. These 
benefits include modeled water quality benefits expressed: (a) as a 
reduction of mixing zone needed for produced water discharges to meet 
Alaska state water quality standards, and (b) as a reduction or 
elimination in exceedances of Alaska state water quality standards at 
the edge of mixing zone from drilling fluids and drill cutting 
discharges.
    (a) Produced Water. The effects of toxic pollutants in current 
(BPT) produced water discharges on receiving water quality and benefits 
of proposed effluent guidelines are evaluated. Plume dispersion 
modeling is performed to project in-stream concentration of 21 
pollutants at the edge of the mixing zones from eight outfalls 
representing Cook Inlet produced water discharge; the in-stream 
concentrations are then compared to the Alaska's state limitations. 
Unlike the Gulf of Mexico, Alaska state requirements do not have 
spatially-defined mixing zones. (Alaska determines the extent of the 
mixing zone needed to achieve compliance with water quality standards 
and evaluates reasonableness of this calculated mixing zone). The water 
quality assessment for Cook Inlet therefore determines the spatial 
extent of mixing zones needed for each evaluated outfall to meet all 
state standards at current discharge and at the proposed BAT. For the 
eight outfalls modeled, the distance from each facility where all state 
standards are met ranges from within 50 feet to 2,500 meters at current 
(BPT) level, and from within 50 feet to 2,000 meters at proposed BAT.
    (b) Drilling Fluids and Drill Cuttings. Discharges of drilling 
fluids and drill cuttings are modelled using Offshore Operator's 
Committee (OOC) Mud Discharge Model to project in-stream concentrations 
of 19 pollutants in water column at the edge of a 100 meter mixing 
zone. The projected pollutant concentrations are then compared to the 
Alaska state water quality standards. The discharge rates are modeled 
in accordance with the maximum discharge rates allowable under the 
existing NPDES general permit for Cook Inlet (1,000 bph in water depths 
exceeding 40 meters; 750 bph in water depths from 20 to 40 meters; and 
500 bph in water depths from 5 to 20 meters). Discharges are prohibited 
in waters between the shore and the 5 meter isobath. The modeling 
results show four standards are exceeded (human health standards for 
beryllium and fluorene and the drinking water standards for aluminum 
and iron) at 40 meter water depth; at 20 meters water depth five 
standards are exceeded (human health standards for beryllium, fluorene, 
and phenanthrene, and drinking water standards for aluminum and iron); 
and six standards are exceeded at the 10 meters water depth (human 
health standards for beryllium, fluorene, and phenanthrene, and 
drinking water standards for aluminum, antimony, and iron) at both 
current BPT discharge and the alternative BAT Option 2 which would 
allow discharge of drilling fluids and drill cuttings with certain 
limitations. The zero discharge option (Option 3) would eliminate all 
projected exceedances.

C. Description of Non-Quantified Benefits

    The Benefit Analysis attempts to quantify, and whenever 
appropriate, to monetize specific environmental benefits that may 
result from the options proposed for this rule. However, some of the 
potential benefits could not be [[Page 9473]] quantified or monetized 
because of the lack of data, or because sufficient information to 
define the causal relationship between coastal oil and gas production 
activities and environmental effects is not available. The evaluated 
non-quantified benefits include: (1) an analysis of environmental 
equity issues related to this rulemaking; (2) effects on threatened or 
endangered species and migratory waterfowl, and potential benefits from 
the proposed rule for ecosystem health for coastal areas of Gulf of 
Mexico and Cook Inlet.
    (1) An Analysis of Environmental Equity Issues. An analysis of 
potential impacts on socioeconomic and ethnic groups in coastal areas 
of Texas, Louisiana, and Cook Inlet conducted to address environmental 
equity issues related to the discharges from coastal oil and gas 
facilities indicates that the subsistence and personal use of fisheries 
in both geographic areas may be appreciable, indicating potential 
environmental equity concerns for low income subsistence and personal 
use anglers including Alaska's Native populations. These socioeconomic 
and ethnic groups are known to be frequent recreational or subsistence 
anglers and are consuming a high rate of seafood, and could 
consequently be at higher than average risk, providing they consume 
seafood that may be contaminated with coastal oil and gas pollutants. 
The subsistence and personal use fisheries in these areas also provide 
food sources that would otherwise have to be purchased elsewhere. In 
addition, Cook Inlet fisheries are of cultural value to Alaskan Native 
populations in that they allow the continuance of a traditional 
lifestyle dependent on the natural resources of the Inlet. A zero 
discharge and control of discharges of produced water, and zero 
discharge of drilling fluids and drill cuttings, and well treatment, 
workover and completion fluids discharges would reduce these impacts.
    (2) Effects on Threatened and Endangered Species. The proposed 
regulation may also have beneficial effects on 32 threatened and 
endangered species in coastal area of Texas and Louisiana (such as 
Brown Pelican, Hawksbill Sea Turtle, Leatherback Sea Turtle, Ocelot, 
and others) that use these areas as part of their habitat. The Upper 
Cook Inlet is an important pathway for spawning fish and nonendangered 
mammals which are resident or occur seasonally in Cook Inlet including 
sea lion, fur seal, harbor seal, sea otter and beluga whale. The Cook 
Inlet area is also a critical habitat for seabirds, shorebirds, and 
migrating waterfowl, including the Cackling Canada Goose, Pacific Black 
Brant, Emperor Goose, and Tule Goose. There are at least four 
endangered cetacean species which may occur in or near Cook Inlet. 
These include the humpback whale, fin whale, sei whale, and gray whale. 
Endangered avian species which may occur as migrants in or near Cook 
Inlet include the short-tailed albatross, American peregrine falcon, 
and Arctic peregrine falcon. Control of produced water and treatment, 
workover, and completion fluids discharges and zero discharge of 
drilling fluids and drill cuttings, would reduce these impacts.

D. EPA Region VI Production Permit

    The benefits of the proposed rule evaluated in the benefit analysis 
are based on discharges and discharge locations that were projected for 
the proposed guidelines (without the published final Region 6 NPDES 
General permits regulating produced water discharges to coastal waters 
in Louisiana and Texas in effect). Because of the close timing of the 
publication of these final General permits and the proposed effluent 
guidelines, little opportunity for in-depth re-analysis of 
environmental benefits occurred. The approach selected is to 
proportionate quantified benefits based on a simple flow proportion 
(i.e., the 29 percent share of produced water flow), attributable to 
the facilities excluded from coverage under the General permits but 
covered by the proposed effluent guidelines. Using this approach, EPA 
estimates that with the Region 6 General permits final, quantified 
monetized benefits may be in the $0.9 to $67 million range in 1990 
dollars ($1.1 to $76 million in 1994 dollars). EPA will re-evaluate 
environmental benefits of the coastal oil and gas subcategory effluent 
guidelines upon promulgation of the final rule.

XIII. Regulatory Implementation

A. Toxicity Limitation for Drilling Fluids and Drill Cuttings

    Under the alternative option EPA considered for drilling fluids and 
drill cuttings, EPA would establish a toxicity limit for this waste 
stream. The toxicity limitation would apply to any periodic blowdown of 
drilling fluid as well as to bulk discharges of drilling fluids and 
drill cuttings systems. The reader is referred to the Offshore 
Guidelines (58 FR, March 4, 1993, page 12502) for an explanation of the 
regulatory implementation for the toxicity limit.

B. Diesel Prohibition for Drilling Fluids and Drill Cuttings

    Under EPA's alternative option for drilling fluids and drill 
cuttings, diesel oil and muds and cuttings contaminated with diesel 
would be prohibited from discharge from Cook Inlet oil platforms. The 
reader is referred to the Offshore Guidelines (58 FR 12502) for a 
discussion on the implementation of this requirement.
C. Upset and Bypass Provisions

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

D. Variances and Modifications

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

E. Synthetic Drilling Fluids

    During the Offshore Oil and Gas Guidelines rulemaking, several 
industry commenters noted recent developments in formulating new 
(synthetic) drilling fluids as substitutes for the traditional water-
based or oil-based fluids. The newer drilling fluids provide improved 
environmental and operational benefits when compared to many of the 
traditional fluids being used. The industry commenters contended that 
the new drilling fluids are not being used due to potential 
interpretation of effluent guidelines and permit limitations. 
Prohibitions on the use of oil-based fluids and inverse emulsions were 
identified as potential barriers to use. Commenters also specifically 
identified the sheen test, which is used to prohibit the discharge of 
fluids and cuttings containing free oil, as giving false positive 
results due to a discoloration which may occur when cuttings containing 
small amounts of some of the synthetic fluids are discharged.
    Since the promulgation of the Offshore Guidelines, data have been 
submitted to document the enhanced [[Page 9474]] environmental 
performance of synthetic fluids. These data show lower toxicity than 
several of the generic fluids used as the basis for the offshore 
toxicity limit of 30,000 ppm (SPP). Results of laboratory and field 
(seabed) evaluations of the biodegradation of one synthetic fluid 
demonstrated good biodegradation. Case histories of field use have 
documented enhanced operational and environmental performance, which 
can include reductions in waste generated and improvement of non-water 
quality impacts. Laboratory data have indicated no detectable priority 
pollutants to be present in synthetic fluids.
    In the preamble to the March 4, 1993, final Offshore Guidelines (58 
FR 12496), EPA identified several issues raised by commenters for which 
additional information was solicited. While EPA wishes to encourage the 
use of less toxic drilling fluids, EPA was concerned that without a 
substitute for the static sheen test, it would not be possible to 
enforce the no free oil limit. EPA also solicited specific data 
concerning the toxicity of new synthetic drilling fluids. Subsequently, 
several industry companies have submitted additional information. EPA 
has reviewed this information and is conducting additional work to 
further evaluate the issues. This work is related to the analytical 
capability to identify the synthetic fluids versus diesel, mineral or 
crude (formation) oils which may cause a sheen when used fluids or 
cuttings are discharged and the toxicity of the synthetic fluids. 
Results of the submitted analytical methods investigations, summarized 
gas chromatography mass copy (GC/MS) identification of polyalphaolafin 
synthetic fluids. The usefulness and limitations of the methods were 
discussed. Use of GC equipment shows promise for detecting low 
concentrations of oil in synthetic fluids, e.g., less than 1 percent, 
but requires further evaluation. Based on the results of the initial 
work and work performed as part of the final Offshore Guidelines to 
differentiate between mineral oil and diesel oil (58 FR 12502), the 
``methods for the determination of Diesel, Mineral and Crude Oils in 
Offshore Oil and Gas Industry Discharges'' (EPA 821-R-92-008) may be 
useful, with or without slight modifications, as an alternative or 
verification step to the free oil and diesel oil discharge 
prohibitions.
    EPA solicits data on the use to-date of synthetic fluids and any 
data, including well logs, toxicity and analytical methods testing and 
in-situ seabed and water column physical, chemical and biological 
testing. EPA will evaluate all submitted data, including information in 
the offshore rulemaking record, in order to assess the environmental 
and performance benefits that could be achieved by using synthetic 
fluids, and take those regulatory actions that may be appropriate to 
mitigate or eliminate barriers to using these fluids.

F. Removal Credits for Indirect Dischargers

    Many industrial facilities discharge large quantities of pollutants 
to POTWs where their wastewaters mix with wastewater from other 
sources, domestic sewage from private residences and run-off from 
various sources prior to treatment and discharge by the POTW. 
Industrial discharges frequently contain pollutants that are generally 
not removed as effectively by treatment at the POTWs as by the 
industries themselves.
    The introduction of pollutants to a POTW from industrial discharges 
may pose several problems. These include potential interference with 
the POTW's operation or pass-through of pollutants if inadequately 
treated. As discussed, Congress, in section 307(b) of the Act, directed 
EPA to establish pretreatment standards to prevent these potential 
problems. Congress also recognized that, in certain instances, POTWs 
could provide some or all of the treatment of an industrial user's 
wastewater that would be required pursuant to the pretreatment 
standard. Consequently, Congress established a discretionary program 
for POTWs to grant ``removal credits'' to their indirect dischargers. 
The credit, in the form of a less stringent pretreatment standard, 
allows an increased concentration of a pollutant in the flow from the 
indirect discharger's facility to the POTW.
    Section 307(b) of the CWA establishes a three-part test for 
obtaining removal credit authority for a given pollutant. Removal 
credits may be authorized only if (1) the POTW ``removes all or any 
part of such toxic pollutant,'' (2) the POTW's ultimate discharge would 
``not violate that effluent limitation, or standard which would be 
applicable to that toxic pollutant if it were discharged'' directly 
rather than through a POTW and (3) the POTW's discharge would ``not 
prevent sludge use and disposal by such [POTW] in accordance with 
section [405].* * *'' Section 307(b).
    EPA has promulgated removal credit regulations in 40 CFR 403.7. The 
United States Court of Appeals for the Third Circuit has interpreted 
the statute to require EPA to promulgate comprehensive sewage sludge 
regulations before any removal credits could be authorized. NRDC v. 
EPA, 790 F.2d 289, 292 (3rd Cir. 1986) cert. denied. 479 U.S. 1084 
(1987). Congress made this explicit in the Water Quality Act of 1987 
which provided that EPA could not authorize any removal credits until 
it issued the sewage sludge use and disposal regulations required by 
section 405(d)(2)(a)(ii).
    Additional discussion of the availability of removal credits is 
contained in the Coastal Technical Development Document. This rule 
proposes to establish pretreatment standards for existing and new 
sources as zero discharge for drilling fluids and drill cuttings; 
produced water; well treatment, workover, and completion fluids; and 
deck drainage, and EPA's pretreatment regulations at 40 CFR 403.7(a)(i) 
limit such authorization to when the POTW demonstrates and continues to 
achieve consistent removal of the pollutant in accordance with 
403.7(b), it is highly unlikely that removal credits would be available 
for these discharges.
    EPA welcomes comment on when and how removal credits may be 
authorized for the pollutants in the circumstances of the coastal oil 
and gas subcategory.

XIV. Related Rulemakings

    In addition to these Coastal Guidelines, EPA is in the process of 
developing other regulations that specifically affect the oil and gas 
industry. These other rulemakings, summarized below, are in the 
developmental stages, and have not, as yet, been proposed. EPA's 
offices are coordinating their efforts with the intent to monitor these 
related rulemakings to assess their collective costs to industry.

A. National Emission Standards for Hazardous Air Pollutants

     National emission standards for hazardous air pollutants (NESHAP) 
are being developed for the oil and gas production industry by EPA's 
Office of Air Quality, Planning and Standards (OAQPS), under authority 
of section 112 (d) of the Clean Air Act as amended in 1990. Section 112 
(d) of the Clean Air Act directs the EPA to promulgate regulations 
establishing hazardous air pollutant (HAP) emissions standards for each 
category of major and area sources that has been listed by EPA for 
regulation under section 112 (c). The 189 pollutants that are 
designated as HAP are listed in section 112 (d). For major sources, or 
facilities which emit 10 or more tons per year (TPY) of an individual 
HAP pollutant or 25 or more TPY of multiple HAPs, the air emission 
standards are based on ``maximum achievable control technology'' or 
MACT. [[Page 9475]] 
    Major sources within the coastal oil and gas subcategory have been 
identified by OAQPS as stand alone glycol dehydrators, tank batteries, 
gas plants, and offshore production platforms. In most cases, OAQPS 
believes that, in order to be a major source, a coastal production 
facility must have glycol dehydrators located on-site: a production 
facility alone may not produce enough emissions to be classified as a 
major source.
    EPA plans to propose MACT standards for the oil and gas industry by 
June 1995 and promulgate them by June 1996. OAQPS estimates that the 
total cost of these standards will be $13 million. Offshore production 
platforms are under the jurisdiction of the Minerals Management Service 
and thus, are not affected by these MACT Standards. EPA solicits 
information regarding the percentage of coastal oil and gas operations 
that will be impacted by this rule.
2. Area of Review Requirements for Injection Wells
    The Safe Drinking Water Act of 1974 (SDWA) charges EPA with 
protecting underground sources of drinking water (USDWs). As part of 
this mandate, EPA developed a program, known as the Underground 
Injection Control Program (UIC), to regulate the underground injection 
of produced water, and promulgate regulations concerning the 
construction, operation, and closure of Class II injection wells. Such 
regulations were originally promulgated in 1980 (45 FR 42500, June, 24, 
1980).
    As a result of a recent 5-year study on the effectiveness of these 
regulations, EPA concluded that more detailed minimum national 
standards, than those promulgated in 1980, are necessary to prevent 
endangerment of USDWs.
    EPA is currently in the process of developing such national 
standards that would establish:
    * A minimum national standard for well construction,
    * More frequent mechanical integrity testing when the construction 
of a well does not meet that minimum standard, and
    * A requirement for Area of Review studies for wells located in 
areas where USDWs are subject to significant risk of indirect flow via 
improperly constructed or abandoned wells.
     The schedule for proposal and promulgation of this rulemaking is 
not specified. Early estimates are that these UIC requirements would 
cost less than $50 million per year for the entire U.S. oil and gas 
industry for the first 5 years after promulgation, and are expected to 
decrease after 5 years.
    It is not known at this time what percentage of this cost will be 
incurred by the coastal oil and gas industry. EPA solicits comment 
regarding this.
3. Spill Prevention, Control, and Countermeasure
    EPA's Oil Pollution Prevention regulation at 40 CFR part 112, 
otherwise known as the Spill Prevention, Control, and Countermeasure 
(SPCC) regulation was promulgated in 1973 under section 311 (j) of the 
CWA. The SPCC regulation applies to all oil extraction and production 
facilities that have an oil storage capacity above certain thresholds 
(i.e. an overall aboveground oil storage capacity greater than 1,320 
gallons or greater than 660 in a single container, or an underground 
oil storage capacity of greater than 42,000 gallons) and are located 
such that a discharge could reasonably be expected to reach U.S. 
waters. EPA estimates that there are approximately 435,000 SPCC-
regulated facilities. Approximately 3,000 of these facilities are 
either coastal or offshore facilities.
    Under the SPCC regulations, facility owners or operators are 
required to prepare and implement written SPCC plans that discuss 
conformance with procedures, methods, and equipment and other 
requirements to prevent discharge of oil and to contain such 
discharges.
    On July 1, 1994, (59 FR 34070, July 1, 1994) EPA issued a final 
rule for certain onshore facilities to prepare, submit to EPA, and 
implement plans to respond to a worst case discharge of oil to meet 
section 4202(a) of the Oil Pollution Act (OPA). EPA is in the process 
of developing requirements to meet Section 420.2(a) of OPA specifically 
for coastal facilities (Note: Coastal and offshore facilities in the 
SPCC program are collectively referred to as ``offshore''. However, 
this current rulemaking is specifically with respect to facilities 
landward of the inner boundary of the territorial seas, and that are 
not onshore.) These regulations will, among other things, require that 
owners or operators of all coastal facilities prepare and submit to the 
Federal government a plan for responding to a worst case discharge of 
oil.
    EPA plans to propose these requirements by 1995, and promulgate 
them by 1996. Costs to the industry to comply with these requirements 
are as yet unknown. EPA solicits information regarding the storage 
capacities of coastal oil production facilities to determine the 
percentage of this industry under the Coastal Oil and Gas subcategory 
that would be affected by the SPCC regulations.

XV. Solicitation of Data and Comments

    EPA encourages public participation in this rulemaking and invites 
comments on any aspect of these proposed regulations. The EPA asks that 
comments address any perceived deficiencies in the record of this 
proposal and that suggested revisions or corrections be supported by 
data where possible. The preceding parts of this notice identify 
specific areas where comments are solicited. In addition, EPA 
particularly requests comments and information on the following:
(1) Combining the Onshore and Coastal Subcategories
    EPA's proposed coastal rule requires zero discharge for all 
drilling fluids and cuttings, as well as zero discharge for all 
produced waters except from Cook Inlet operations. Because the effluent 
limitations for the onshore subcategory of the oil and gas industry 
require zero discharge for all oil and gas wastes (44 FR 22069, April 
13, 1979), EPA is considering the appropriateness of combining these 
two subcategories for regulation of the major wastestreams. Combining 
the subcategories would not only simplify the rule itself but, could 
result in reduction of administrative burden in permit development, and 
facility location determination; EPA solicits comment on the 
appropriateness of combining these two subcategories.

XVI. Background Documents

     The basis for this regulation is detailed in two major documents, 
each of which is supported in turn by additional information and 
analyses in the rulemaking record. EPA's technical foundation for the 
regulation is detailed in the Development Document for Proposed 
Effluent Limitations Guidelines and Standards for the Coastal 
Subcategory of the Oil and Gas Extraction Point Source Category. EPA's 
economic analysis is presented in the Economic Impact Analysis of 
Proposed Effluent Limitations Guidelines and Standards for the Coastal 
Subcategory of the Offshore Oil and Gas Industry. These documents are 
available from the Office of Water Resource Center. (See Addresses) The 
public record for this rulemaking is available for review at EPA's 
Water Docket. (See ADDRESSES)

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

Act--Clean Water Act.
Agency--Environmental Protection Agency.
BADCT--The best available demonstrated control technology, for new 
sources under section 306 of the Clean Water Act. [[Page 9476]] 
BAT--The best available technology economically achievable, under 
section 304(b)(2)(B) of the Clean Water Act.
bbl--barrel, 42 U.S. gallons.
bpd--barrels per day.
bpy--barrels per year.
BCT--Best conventional pollutant control technology under section 
304(b)(4)(B) of the Clean Water Act.
BMP--Best management practices under section 304(e) of the Clean 
Water Act.
BOD--Biochemical oxygen demand.
BOE--Barrels of oil equivalent.
BPT--Best practicable control technology currently available, under 
section 304(b)(1) of the Clean Water Act.
CFR--Code of Federal Regulations.
Clean Water Act--Federal Water Pollution Control Act Amendments of 
1972 (33 U.S.C. 1251 et seq.).
Conventional pollutants--Constituents of wastewater as determined by 
section 304(a)(4) of the Clean Water Act, including, but not limited 
to, pollutants classified as biochemical oxygen demanding, suspended 
solids, oil and grease, fecal coliform, and pH.
CWA--Clean Water Act.
Direct discharger--A facility which discharges or may discharge 
pollutants to waters of the United States.
EIA--Economic Impact Analysis.
EPA--Environmental Protection Agency.
Indirect discharger--A facility that introduces wastewater into a 
publicly owned treatment works.
IRR--Internal Rate of Return.
LC50--The concentration of a test material that is lethal to 50 
percent of the test organisms in a bioassay.
mg/l--milligrams per liter.
Nonconventional pollutants--Pollutants that have not been designated 
as either conventional pollutants or priority pollutants.
NORM--Naturally Occurring Radioactive Materials.
NPDES--The National Pollutant Discharge Elimination System.
NPV--Net Present Value.
NSPS--New source performance standards under section 306 of the 
Clean Water Act.
OCS--Offshore Continental Shelf.
OMB--Office of Management and Budget.
POTW--Publicly Owned Treatment Works.
ppm--parts per million.
Priority pollutants--The 65 pollutants and classes of pollutants 
declared toxic under section 307(a) of the Clean Water Act.
PSES--Pretreatment standards for existing sources of indirect 
discharges, under section 307(b) of the Clean Water Act.
PSNS--Pretreatment standards for new sources of indirect discharges, 
under sections 307 (b) and (c) of the Clean Water Act.
SIC--Standard Industrial Classification.
SPP--Suspended particulate phase.
TSS--Total Suspended Solids.
Coastal Technical Development Document--Development Document for 
Proposed Effluent Limitations Guidelines and New Source Performance 
Standards for the Coastal Subcategory of the Oil and Gas Extraction 
Point Source Category.
Offshore Technical Development Document--Development Document for 
Effluent Limitations Guidelines and New Source Performance Standards 
for the Offshore Subcategory of the Oil and Gas Extraction Point 
Source Category.
U.S.C.--United States Code.

List of Subjects in 40 CFR Part 435

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

    Dated: January 31, 1995.
Carol M. Browner,
Administrator.
    For the reasons set forth in the preamble, 40 CFR part 435 is 
proposed to be amended as follows:

PART 435--OIL AND GAS EXTRACTION POINT SOURCE CATEGORY

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

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

    2. Subpart A is proposed to be amended by revising Sec. 435.10 to 
read as follows:

Subpart A--Offshore Subcategory


Sec. 435.10  Applicability; description of the offshore subcategory.

    The provisions of this subpart are applicable to those facilities 
engaged in field exploration, drilling, well production, and well 
treatment in the oil and gas industry which are located in waters that 
are seaward of the inner boundary of the territorial seas 
(``offshore'') as defined in section 502(g) of the Clean Water Act.
    3. Subpart G consisting of Sec. 435.70 is proposed to be added to 
read as follows:

Subpart G--General Provisions


Sec. 435.70  Applicability.

    (a) Purpose. This subpart is intended to prevent oil and gas 
facilities subject to this part from circumventing the effluent 
limitations guidelines and standards applicable to those facilities by 
moving effluent produced in one subcategory to another subcategory for 
disposal under less stringent requirements than intended by this part.
    (b) Applicability. The effluent limitations and standards 
applicable to an oil and gas facility shall be determined as follows:
    (1) An oil and gas facility, operator, or its agent or contractor 
may move its wastewaters from a facility located in one subcategory to 
another subcategory for treatment and return it to a location covered 
by the original subcategory for disposal. In such case, the effluent 
limitations guidelines, new source performance standards, or 
pretreatment standards for the original subcategory apply.
    (2) An oil and gas facility, operator, or its agent or contractor 
may move its wastewaters from a facility located in one subcategory to 
another subcategory for disposal or treatment and disposal, provided:
    (i) If an oil and gas facility, operator or its agent or contractor 
moves wastewaters from a wellhead located in one subcategory to another 
subcategory where oil and gas facilities are governed by less stringent 
effluent limitations guidelines, new source performance standards, or 
pretreatment standards, the more stringent effluent limitations 
guidelines, new source performance standards, or pretreatment standards 
applicable to the subcategory where the wellhead is located shall 
apply.
    (ii) If an oil and gas facility, operator or its agent moves 
effluent from a wellhead located in one subcategory to another 
subcategory where oil and gas facilities are governed by more stringent 
effluent limitations guidelines, new source performance standard, or 
pretreatment standards, the more stringent effluent limitations 
guidelines, new source performance standards, or pretreatment standards 
applicable at the point of discharge shall apply.
    4. Subpart D is proposed to be amended by revising Secs. 435.40 and 
435.41 to read as follows:

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 means:
    (a) Any oil and gas facility located in or on a water of the United 
States landward of the territorial seas; or
    (b)(1) Oil and gas facilities in existence on April 13, 1979 or 
thereafter and are located landward from the inner boundary of the 
territorial seas and bounded on the inland side by the line defined by 
the inner boundary of the territorial seas eastward of the point 
defined by 89 deg.45' W. Longitude and 29 deg.46' N. 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'.                 
[[Page 9477]]
                                                                        
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, 92 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' W. Longitude and Southward to the U.S.--
Mexican border.
Sec. 435.41  Specialized definitions.

    For the purpose of this subpart:
    (a) Except as provided in this section, the general definitions, 
abbreviations and methods of analysis set forth in 40 CFR part 401 
shall apply to this subpart.
    (b) The term average of daily values for 30 consecutive days is the 
average of the daily values obtained during any 30 consecutive day 
period.
    (c) The term Cook Inlet means all of the production platforms 
(``existing sources'' or ``existing dischargers'') and exploratory 
operations (``new dischargers'') addressed by EPA's Region X in the 
general NPDES permit for Cook Inlet.
    (d) The term daily values as applied to produced water effluent 
limitations and NSPS refers to the daily measurements used to assess 
compliance with the maximum for any one day.
    (e) The term deck drainage refers to any waste resulting from deck 
washings, spillage, rainwater, and runoff from gutters and drains 
including drip pans and work areas within facilities subject to this 
subpart.
    (f) The term development facility means any fixed or mobile 
structure subject to this subpart that is engaged in the drilling of 
productive wells.
    (g) The term dewatering effluent means wastewater from drilling 
fluids and cuttings dewatering activities (including but not limited to 
reserve pits or other tanks or vessels, and chemical or mechanical 
treatment occurring during the drilling solids separation/recycle/
disposal process).
    (h) The term diesel oil refers to the grade of distillate fuel oil, 
as specified in the American Society for Testing and Materials Standard 
Specification for Diesel Fuel Oils D975-91, that is typically used as 
the continuous phase in conventional oil-based drilling fluids. This 
incorporation by reference was approved by the Director of the Federal 
Register in accordance with 5 U.S.C. 552(a) and 1 CFR Part 51. Copies 
may be obtained from the American Society for Testing and Materials, 
1916 Race Street, Philadelphia, PA 19103. Copies may be inspected at 
the Office of the Federal Register, 800 North Capitol Street, N.W., 
Suite 700, Washington, DC.
    (i) The term domestic waste refers to materials discharged from 
sinks, showers, laundries, safety showers, eye-wash stations, hand-wash 
stations, fish cleaning stations, and galleys located within facilities 
subject to this subpart.
    (j) The term drill cuttings refers to the particles generated by 
drilling into subsurface geologic formations and carried to the surface 
with the drilling fluid.
    (k) The term drilling fluid refers to the circulating fluid (mud) 
used in the rotary drilling of wells to clean and condition the hole 
and to counterbalance formation pressure. A water-based drilling fluid 
is the conventional drilling mud in which water is the continuous phase 
and the suspending medium for solids, whether or not oil is present. An 
oil-based drilling fluid has diesel oil, mineral oil, or some other oil 
as its continuous phase with water as the dispersed phase.
    (l) The term exploratory facility means any fixed or mobile 
structure subject to this subpart that is engaged in the drilling of 
wells to determine the nature of potential hydrocarbon reservoirs.
    (m) The term garbage means all kinds of victual, domestic, and 
operational waste, excluding fresh fish and parts thereof, generated 
during the normal operation of coastal oil and gas facility and liable 
to be disposed of continuously or periodically, except dishwater, 
graywater, and those substances that are defined or listed in other 
Annexes to MARPOL 73/78. MARPOL 73/78 is available from the National 
Technical Information Service (NTIS) (reference number ADA 183 505), 
5285 Port Royal Road, Springfield, VA 22161.
    (n) The term maximum as applied to BAT effluent limitations and 
NSPS for drilling fluids and drill cuttings means the maximum 
concentration allowed as measured in any single sample of the barite.
    (o) The term maximum for any one day as applied to BPT, BCT and BAT 
effluent limitations and NSPS for oil and grease in produced water 
means the maximum concentration allowed as measured by the average of 
four grab samples collected over a 24-hour period that are analyzed 
separately. Alternatively, for BAT and NSPS the maximum concentration 
allowed may be determined on the basis of physical composition of the 
four grab samples prior to a single analysis.
    (p) The term minimum as applied to BAT effluent limitations and 
NSPS for drilling fluids and drill cuttings means the minimum 96-hour 
LC50 value allowed as measured in any single sample of the discharged 
waste stream. The term minimum as applied to BPT and BCT effluent 
limitations and NSPS for sanitary wastes means the minimum 
concentration value allowed as measured in any single sample of the 
discharged waste stream.
    (q) The term M9IM means those coastal facilities continuously 
manned by nine (9) or fewer persons or only intermittently manned by 
any number of persons.
    (r) The term M10 means those coastal facilities continuously manned 
by ten (10) or more persons.
    (s)(1) The term new source means any facility or activity of this 
subcategory that meets the definition of ``new source'' under 40 CFR 
122.2 and meets the criteria for determination of new sources under 40 
CFR 122.29(b) applied consistently with all of the following 
definitions:
    (i) The term water area as used in the term ``site'' in 40 CFR 
122.29 and 122.2 means the water area and ocean floor beneath any 
exploratory, development, or production facility where such facility is 
conducting its exploratory, development or production activities.
    (ii) The term significant site preparation work as used in 40 CFR 
122.29 means the process of surveying, clearing or preparing an area of 
the ocean floor for the purpose of constructing or placing a 
development or production facility on or over the site.
    (2) ``New Source'' does not include facilities covered by an 
existing NPDES permit immediately prior to the effective date of this 
subpart pending [[Page 9478]] EPA issuance of a new source NPDES 
permit.
    (t) The term no discharge of free oil means that waste streams may 
not be discharged when they would cause a film or sheen upon or a 
discoloration of the surface of the receiving water or fail the static 
sheen test defined in Appendix 1 to 40 CFR part 435, subpart A.
    (u) The term produced sand refers to slurried particles used in 
hydraulic fracturing, the accumulated formation sands and scales 
particles generated during production. Produced sand also includes 
desander discharge from the produced water waste stream, and blowdown 
of the water phase from the produced water treating system.
    (v) The term produced water refers to the water (brine) brought up 
from the hydrocarbon-bearing strata during the extraction of oil and 
gas, and can include formation water, injection water, and any 
chemicals added downhole or during the oil/water separation process.
    (w) The term production facility means any fixed or mobile 
structure subject to this subpart that is either engaged in well 
completion or used for active recovery of hydrocarbons from producing 
formations. It includes facilities that are engaged in hydrocarbon 
fluids separation even if located separately from wellheads.
    (x) The term sanitary waste refers to human body waste discharged 
from toilets and urinals located within facilities subject to this 
subpart.
    (y) The term static sheen test refers to the standard test 
procedure that has been developed for this industrial subcategory for 
the purpose of demonstrating compliance with the requirement of no 
discharge of free oil. The methodology for performing the static sheen 
test is presented in appendix 1 to 40 CFR part 435, subpart A.
    (z) The term toxicity as applied to BAT effluent limitations and 
NSPS for drilling fluids and drill cuttings refers to the bioassay test 
procedure presented in appendix 2 of 40 CFR part 435, subpart A.
    (aa) The term well completion fluids refers to salt solutions, 
weighted brines, polymers, and various additives used to prevent damage 
to the well bore during operations which prepare the drilled well for 
hydrocarbon production.
    (bb) The term well treatment fluids refers to any fluid used to 
restore or improve productivity by chemically or physically altering 
hydrocarbon-bearing strata after a well has been drilled.
    (cc) The term workover fluids refers to salt solutions, weighted 
brines, polymers, or other specialty additives used in a producing well 
to allow for maintenance, repair or abandonment procedures.
    (dd) The term 96-hour LC50 refers to the concentration (parts per 
million) or percent of the suspended particulate phase (SPP) from a 
sample that is lethal to 50 percent of the test organisms exposed to 
that concentration of the SPP after 96 hours of constant exposure.
    5. Section 435.42 is proposed to be amended by revising the 
introductory text and be in the table to paragraph (a) by adding at the 
end an entry for ``Produced Sand'' to read as follows:


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 through 125.32, any existing 
point source subject to this subpart must achieve the following 
effluent limitations representing the degree of effluent reduction 
attainable by the application of the best practicable control 
technology currently available.
    (a)  * * *

                        BPT Effluent Limitations                        
------------------------------------------------------------------------
                                                               Residual 
                                           Average of values   chlorine 
Pollutant parameter   Maximum for any 1   for 30 consecutive    minimum 
    waste source             day            days shall not     for any 1
                                                exceed            day   
------------------------------------------------------------------------
                                                                        
       *                  *                  *                  *       
                  *                  *                  *               
Produced Sand......  zero discharge.....  zero discharge....  NA        
------------------------------------------------------------------------

* * * * *
    6. Sections 435.43 through 435.47 are proposed to be added to 
subpart D to read as follows:


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 through 125.32, any existing 
point source subject to this Subpart must achieve the following 
effluent limitations representing the degree of effluent reduction 
attainable by the application of the best available technology 
economically achievable (BAT):

                                            BAT Effluent Limitations                                            
----------------------------------------------------------------------------------------------------------------
               Stream                     Pollutant parameter                BAT effluent limitations           
----------------------------------------------------------------------------------------------------------------
Produced Water:                                                                                                 
    (A) All coastal areas except      ..........................  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 and Drill Cuttings:                                                                             
Option 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.                                      
[[Page 9479]]
                                                                                                                
                                      Cadmium...................  3 mg/kg dry weight maximum in the stock       
                                                                   barite.                                      
                                      Toxicity..................  Minimum 96-hour LC50 of the SPP shall be 3    
                                                                   percent by volume.\3\                        
Option 2:                                                                                                       
    (A) All coastal areas except      ..........................  No discharge.                                 
     Cook Inlet.                                                                                                
    (B) Cook Inlet..................  Free Oil1\1\..............  No discharge.                                 
                                      Diesel Oil................  No discharge.                                 
                                      Mercury...................  1 mg/kg dry weight maximum in the stock       
                                                                   barite.                                      
                                      Cadmium...................  3 mg/kg dry weight maximum in the stock       
                                                                   barite.                                      
                                      Toxicity..................  Minimum 96-hour LC50 of the SPP shall be 10   
                                                                   percent to 100 percent by volume.\3\         
Option 3:                                                                                                       
    All coastal areas...............  ..........................  No discharge.                                 
Well Treatment, Workover and                                                                                    
 Completion Fluids:                                                                                             
Option 1:                                                                                                       
    (A) All coastal areas except      Free Oil\1\...............  No discharge.                                 
     freshwater of Texas and                                                                                    
     Louisiana.                                                                                                 
    (B) Freshwaters of Texas and      ..........................  No discharge.                                 
     Louisiana.                                                                                                 
Option 2:                                                                                                       
    (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.                                
Domestic Waste......................  Foam......................  No discharge.                                 
----------------------------------------------------------------------------------------------------------------
\1\As determined by the static sheen test                                                                       
\2\As determined by the presence of a film or sheen upon or a discoloration of the surface of the receiving     
  water (visual sheen).                                                                                         
\3\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).

    Except as provided in 40 CFR 125.30 through 125.32, any existing 
point source subject to this subpart must achieve the following 
effluent limitations representing the degree of effluent reduction 
attainable by the application of the best conventional pollutant 
control technology (BCT):

                                            BCT Effluent Limitations                                            
----------------------------------------------------------------------------------------------------------------
               Stream                     Pollutant parameter                BCT effluent limitations           
----------------------------------------------------------------------------------------------------------------
Produced Water (all facilities).....  Oil & Grease..............  The maximum for any one day shall not exceed  
                                                                   72 mg/l and the 30-day average shall not     
                                                                   exceed 48 mg/l.                              
Drilling Fluids and Drill Cuttings:                                                                             
    All facilities except Cook Inlet  ..........................  No discharge.                                 
    Cook Inlet......................  Free Oil..................  No discharge.\1\                              
Well Treatment, Workover and          Free Oil..................  No discharge.\1\                              
 Completion Fluids.                                                                                             
Produced Sand.......................  ..........................  No discharge                                  
Deck Drainage.......................  Free Oil..................  No discharge.\2\                              
Sanitary Waste:                                                                                                 
    Sanitary M10....................  Residual Chlorine.........  Minimum of 1 mg/l maintained as close to this 
                                                                   concentration as possible.                   
    Sanitary M91M...................  Floating Solids...........  No discharge.                                 
Domestic Waste......................  Floating Solids and         No discharge of Floating Solids or garbage.\3\
                                       garbage.                                                                 
----------------------------------------------------------------------------------------------------------------
\1\As determined by static sheen test 40 CFR part 435, subpart A, appendix 1.                                   
\2\As determined by the presence of a film or sheen upon or a discoloration of the surface of the receiving     
  water (visual sheen).                                                                                         
\3\As defined in 40 CFR 435.41(1).                                                                              

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 9480]]
                                            NSPS Effluent Limitations                                           
----------------------------------------------------------------------------------------------------------------
               Stream                     Pollutant parameter             NSPS/PSNS effluent limitations        
----------------------------------------------------------------------------------------------------------------
Produced Water (all facilities).....  ..........................  No discharge.                                 
Drilling Fluids and Drill Cuttings:                                                                             
Option 1:                                                                                                       
    (A) All coastal areas except      ..........................  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.                                      
                                      Cadmium...................  3 mg/kg dry weight maximum in the stock       
                                                                   barite.                                      
                                      Toxicity..................  Minimum 96-hour LC50 of the SPP shall be 3    
                                                                   percent by volume.\3\                        
Option 2:                                                                                                       
    (A) All coastal areas except      ..........................  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.                                      
                                      Cadmium...................  3 mg/kg dry weight maximum in the stock       
                                                                   barite.                                      
                                      Toxicity..................  Minimum 96-hour LC50 of the SPP shall be 10   
                                                                   percent to 100 percent to 100 percent by     
                                                                   volume.\3\                                   
Option 3:                                                                                                       
    All coastal areas...............  ..........................  No discharge.                                 
Well Treatment, Workover and                                                                                    
 Completion Fluids:                                                                                             
Option 1:                                                                                                       
    (A) All coastal areas except      Free Oil\1\...............  No discharge.                                 
     freshwater of Texas and                                                                                    
     Louisiana.                                                                                                 
    (B) Freshwaters of Texas and      ..........................  No discharge.                                 
     Louisiana.                                                                                                 
Option 2:                                                                                                       
    (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 floating solids or garbage or 
                                       Garbage\4\ and Foam.        foam.                                        
----------------------------------------------------------------------------------------------------------------
\1\As determined by the static sheen test.                                                                      
\2\As determined by the presence of a film or sheen upon or a discoloration of the surface of the receiving     
  water (visual sheen).                                                                                         
\3\As determined by the toxicity test (see appendix 2 of 40 CFR part 435, subpart A).                           
\4\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 
by the effective date of this rule achieve the following pretreatment 
standards for existing sources (PSES).

                                                                                                                
[[Page 9481]]
                                                                                    PSNS Effluent Limitations                                                                                   
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                    Pollutant     PSNS effluent                                                                                                                                                 
     Stream         parameter      limitations                                                                                                                                                  
------------------------------------------------                                                                                                                                                
Produced         ..............  No discharge.                                                                                                                                                  
 Water(all                                                                                                                                                                                      
 facilities).                                                                                                                                                                                   
Drilling fluids  ..............  No discharge.                                                                                                                                                  
 and Drill                                                                                                                                                                                      
 Cuttings.                                                                                                                                                                                      
Well Treatment,  ..............  No discharge.                                                                                                                                                  
 Workover and                                                                                                                                                                                   
 Completion                                                                                                                                                                                     
 Fluids.                                                                                                                                                                                        
Produced Sand..  ..............  No discharge.                                                                                                                                                  
Deck Drainage..  ..............  No discharge.                                                                                                                                                  
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

[FR Doc. 95-3602 Filed 2-16-95; 8:45 am]
BILLING CODE 6560-50-P