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