[Federal Register Volume 66, Number 14 (Monday, January 22, 2001)]
[Rules and Regulations]
[Pages 6850-6919]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 01-361]
[[Page 6849]]
-----------------------------------------------------------------------
Part IV
Environmental Protection Agency
-----------------------------------------------------------------------
40 CFR Parts 9 and 435
Effluent Limitations Guidelines and New Source Performance Standards
for the Oil and Gas Extraction Point Source Category; OMB Approval
Under the Paperwork Reduction Act: Technical Amendment; Final Rule
Federal Register / Vol. 66 , No. 14 / Monday, January 22, 2001 /
Rules and Regulations
[[Page 6850]]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 9 and 435
[FRL-6929-8]
RIN 2040-AD14
Effluent Limitations Guidelines and New Source Performance
Standards for the Oil and Gas Extraction Point Source Category; OMB
Approval Under the Paperwork Reduction Act: Technical Amendment
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final Rule; technical amendment.
-----------------------------------------------------------------------
SUMMARY: EPA is publishing final regulations establishing technology-
based effluent limitations guidelines and standards for the discharge
of synthetic-based drilling fluids (SBFs) and other non-aqueous
drilling fluids from oil and gas drilling operations into waters of the
United States. Oil and gas extraction facilities generate cuttings
wastes from drilling operations. This regulation applies to existing
and new sources that perform oil and natural gas extraction drilling in
certain offshore and coastal waters. The final rule allows a controlled
discharge of SBF-cuttings anywhere offshore of Alaska and offshore of
the rest of the United States beyond three miles from shore. This
regulation prohibits discharge of such fluids in coastal Cook Inlet,
Alaska, unless certain findings are made by the permit authority. The
final rule prohibits the discharge of SBFs not associated with drill
cuttings into all waters of the United States.
Compliance with this rule is estimated to reduce the annual
discharge of cuttings by 118 million pounds per year for new and
existing sources. This rule will also lead to a decrease of 2,927 tons
of air emissions and 200,817 barrels of oil equivalent (BOE) per year
for new and existing sources. EPA estimates that the rule will result
in annual savings of $48.9 million and no adverse economic impacts to
the industry as a whole. EPA also incorporated Best Management
Practices (BMPs) into the final rule to provide industry with
additional flexibility in meeting today's final rule. In compliance
with the Paperwork Reduction Act (PRA), this action also makes a
technical amendment to the table in part 9 that lists the Office of
Management and Budget (OMB) control numbers issued under the PRA for
today's final rule. EPA is amending part 9 to include the OMB control
number for the information collection requirements associated with the
BMPs promulgated in today's final rule.
DATES: This regulation shall become effective February 21, 2001. For
judicial review purposes, this final rule is promulgated as of 1 p.m.
Eastern Time on February 5, 2001, as provided in 40 CFR 23.2. The
incorporation by reference of certain publications listed in the
regulations is approved by the Director of the Office of Federal
Register as of February 21, 2001.
ADDRESSES: The public record is available for review in the EPA Water
Docket, East Tower Basement, Room EB-57, 401 M St. SW., Washington, DC
20460. The public record for this rule has been established under
docket number W-98-26, and includes supporting documentation, but does
not include any information claimed as Confidential Business
Information (CBI). The record is available for inspection from 9 a.m.
to 4 p.m., Monday through Friday, excluding legal holidays. For access
to docket materials, please call (202) 260-3027 to schedule an
appointment.
FOR FURTHER INFORMATION CONTACT: For additional technical information
contact Mr. Carey A. Johnston at (202) 260-7186 or send E-mail to:
[email protected]. For additional economic information contact Mr.
James Covington at (202) 260-5132 or send E-mail to:
[email protected].
SUPPLEMENTARY INFORMATION:
Regulated Entities
Entities potentially regulated by this action include:
------------------------------------------------------------------------
Category Examples of regulated entities
------------------------------------------------------------------------
Industry..................... Facilities engaged in the drilling of
wells in the oil and gas industry in
areas defined as ``coastal'' or
``offshore'' and discharging in
geographic areas where drilling wastes
are allowed for discharge (anywhere
offshore of Alaska and offshore of the
rest of the United States beyond three
miles from shore, and the coastal waters
of Cook Inlet, Alaska). Includes certain
facilities covered under Standard
Industrial Classification code 13 and
North American Industrial Classification
System codes 211111 and 213111.
------------------------------------------------------------------------
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
action. This table lists the types of entities that EPA is now aware
could potentially be regulated by this action. Other types of entities
not listed in the table could also be regulated. To determine whether
your facility is regulated by this action, you should carefully examine
the applicability criteria in 40 CFR part 435 (see Secs. 435.10 and
435.40). If you have questions regarding the applicability of this
action to a particular entity, consult the person listed for technical
information in the preceding FOR FURTHER INFORMATION CONTACT section.
Compliance Dates
Deadlines for compliance with Best Practicable Control Technology
Currently Available (BPT), Best Conventional Pollutant Control
Technology (BCT), and Best Available Technology Economically Achievable
(BAT) are established in National Pollutant Discharge Elimination
System (NPDES) permits. A new source must comply with New Source
Performance Standards (NSPS) on the date the new source commences
discharging.
Technical Amendments to Part 9
EPA is amending the table of currently approved information
collection request (ICR) control numbers issued by OMB for various
regulations. The amendment updates the table to list those information
collection requirements promulgated under today's final rule. The
affected regulations are codified at 40 CFR part 9. EPA will continue
to present OMB control numbers in a consolidated table format to be
codified in 40 CFR part 9 of the Agency's regulations, and in each CFR
volume containing EPA regulations. The table lists CFR citations with
reporting, recordkeeping, or other information collection requirements,
and the current OMB control numbers. This listing of the OMB control
numbers and their subsequent codification in the CFR satisfies the
requirements of the Paperwork Reduction Act (44 U.S.C. 3501 et seq.)
and OMB's implementing regulations at 5 CFR part 1320.
This ICR was previously subject to public notice and comment prior
to OMB approval. Due to the technical
[[Page 6851]]
nature of the table, EPA finds that further notice and comment is
unnecessary. As a result, EPA finds that there is ``good cause'' under
section 553(b)(B) of the Administrative Procedure Act, 5 U.S.C.
553(b)(B), to amend this table without prior notice and comment. As a
result of today's technical amendment pertaining to BMPs, EPA is now
authorized under the Paperwork Reduction Act to conduct or sponsor the
information collection requirements in 40 CFR 435.13, 435.15, 435.43,
and 435.45.
Supporting Documentation
The rules promulgated today are supported by several major
documents:
1. ``Economic Analysis of Final Effluent Limitations Guidelines and
Standards for Synthetic-Based Drilling Fluids and other Non-Aqueous
Drilling Fluids in the Oil and Gas Extraction Point Source Category''
(EPA-821-B-00-012). Hereafter referred to as the SBF Economic Analysis,
this document presents the analysis of compliance costs and/or savings;
facility closures; and changes in rate of return. In addition, impacts
on employment and affected communities, foreign trade, specific
demographic groups, and new sources also are considered.
2. ``Development Document for Final Effluent Limitations Guidelines
and Standards for Synthetic-Based Drilling Fluids and other Non-Aqueous
Drilling Fluids in the Oil and Gas Extraction Point Source Category''
(EPA-821-B-00-013). Hereafter referred to as the SBF Development
Document, the document presents EPA's technical conclusions concerning
the promulgated rules. This document describes, among other things, the
data collection activities, the wastewater treatment technology
options, effluent characterization, effluent reduction of the
wastewater treatment technology options, estimate of costs to the
industry, and estimate of effects on non-water quality environmental
impacts.
3. ``Environmental Assessment of Final Effluent Limitations
Guidelines and Standards for Synthetic-Based Drilling Fluids and other
Non-Aqueous Drilling Fluids in the Oil and Gas Extraction Point Source
Category'' (EPA-821-B-00-014). Hereafter referred to as the SBF
Environmental Assessment, the document presents the analysis of water
quality impacts for each regulatory option. EPA describes the
environmental characteristics of SBF drilling wastes, types of
anticipated impacts, and pollutant modeling results for water column
concentrations, pore water concentrations, and human health effects via
consumption of affected seafood.
4. ``Statistical Analyses Supporting Final Effluent Limitations
Guidelines and Standards for Synthetic-Based Drilling Fluids and other
Non-Aqueous Drilling Fluids in the Oil and Gas Extraction Point Source
Category'' (EPA-821-B-00-015). Hereafter referred to as the SBF
Statistical Support Document, this document presents analyses of
retention on cuttings of SBF. EPA describes the performance
characteristics of cuttings treatment technologies and calculates
summary statistics for use as numerical limits.
How To Obtain Supporting Documents
All documents are available from the National Service Center for
Environmental Publications, PO Box 42419, Cincinnati, OH 45242-2419,
(800) 490-9198. The supporting technical documentation (e.g., SBF
Development Document) and previous technical documentation and Federal
Register notices can also be obtained on the Internet, located at
WWW.EPA.GOV/OST/GUIDE. This website also links to an electronic version
of today's final rule.
Overview
This preamble includes a description of the legal authority for
these final regulations; a summary of the final regulations; background
information on the industry and its processes; a description of the
technical and economic methodologies and data used by EPA to develop
these regulations; and a summary of EPA responses to major comments
received on the Proposal (February 3, 1999; 64 FR 5488) and Notice of
Data Availability (April 21, 2000; 65 FR 21548). The definitions,
acronyms, and abbreviations used in this preamble are defined in
Appendix A.
Organization of This Document
I. Legal Authority
II. Background
A. Clean Water Act
B. Pollution Prevention Act
C. Profile of Industry
D. Proposed Rule
E. Notice of Data Availability
III. Summary of Data and Information Received in Response to the
Notice of Data Availability
A. Pollutant Loading and Numeric Limit Analyses
B. Compliance Costs Analyses
C. Economic Impacts Analyses
D. Water Quality Impact and Human Health Analyses
E. Non-Water Quality Environmental Impact Analyses
F. Compliance Analytical Methods
IV. Summary of Revisions Based on Notice of Data Availability
Comments
A. Pollutant Loading Analyses
B. Compliance Costs Analyses
C. Economic Impacts Analyses
D. Water Quality Impact and Human Health Analyses
E. Non-Water Quality Environmental Impact Analyses
F. Numerical Limits for Retention of SBF Base Fluid on SBF-
cuttings
V. Development and Selection of Effluent Limitations Guidelines and
Standards
A. Waste Generation and Characterization
B. Selection of Pollutant Parameters
C. Regulatory Options Considered and Selected for Drilling Fluid
Not Associated with Drill Cuttings
D. BPT Technology Options Considered and Selected for Drilling
Fluid Associated with Drill Cuttings
E. BCT Technology Options Considered and Selected for Drilling
Fluid Associated with Drill Cuttings
F. BAT Technology Options Considered and Selected for Drilling
Fluid Associated with Drill Cuttings
G. NSPS Technology Options Considered and Selected for Drilling
Fluid Associated with Drill Cuttings
H. PSES and PSNS Technology Options
I. Best Management Practices (BMPs) to Demonstrate Compliance
with Numeric BAT Limitations and NSPS for Drilling Fluid Associated
with Drill Cuttings
VI. Costs and Pollutant Reductions for Final Regulation
A. Compliance Costs
B. Pollutant Reductions
VII. Economic Impacts of Final Regulation
A. Impacts Analysis
B. Small Business Analysis
VIII. Water Quality and Non-Water Quality Environmental Impacts of
Final Regulation
A. Overview of Water Quality and Non-Water Quality Environmental
Impacts
B. Water Quality Modeling
C. Human Health Effects Modeling
D. Seabed Surveys
E. Energy Impacts
F. Air Emission Impacts
G. Air Emissions Monetized Human Health Benefits
H. Solid Waste Impacts
I. Other Factors
IX. Regulatory Requirements
A. Executive Order 12866: Regulatory Planning and Review
B. Regulatory Flexibility Act (RFA), as amended by the Small
Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5
U.S.C. 601 et seq.
C. Submission to Congress and the General Accounting Office
D. Paperwork Reduction Act
E. Unfunded Mandates Reform Act
F. Executive Order 13084: Consultation and Coordination with
Indian Tribal Governments
G. Executive Order 13132: Federalism
H. National Technology Transfer and Advancement Act
I. Executive Order 13045: Protection of Children from
Environmental Health Risks and Safety Risks
[[Page 6852]]
J. Executive Order 13158: Marine Protected Areas
X. Regulatory Implementation
A. Implementation of Limitations and Standards
B. Upset and Bypass Provisions
C. Variances and Modifications
D. Relationship of Effluent Limitations to NPDES Permits &
Monitoring Requirements
E. Analytical Methods
Appendix A: Definitions, Acronyms, and Abbreviations Used in This
Preamble
I. Legal Authority
EPA is promulgating these regulations under the authority of
sections 301, 304, 306, 307, 308, 402, and 501 of the Clean Water Act,
33 U.S.C. 1311, 1314, 1316, 1317, 1318, 1342 and 1361. The technical
amendment to part 9 is promulgated under the authority of 7 U.S.C. 135
et seq., 136-136y; 15 U.S.C. 2001, 2003, 2005, 2006, 2601-2671; 21
U.S.C. 331j, 346a, 348; 31 U.S.C. 9701; 33 U.S.C. 1251 et seq., 1311,
1313d, 1314, 1318, 1321, 1326, 1330, 1342, 1344, 1345 (d) and (e),
1361; E.O. 11735, 38 FR 21243, 3 CFR, 1971-1975 Comp. p. 973; 42 U.S.C.
241, 242b, 243, 246, 300f, 300g, 300g-1, 300g-2, 300g-3, 300g-4, 300g-
5, 300g-6, 300j-1, 300j-2, 300j-3, 300j-4, 300j-9, 1857 et seq., 6901-
6992k, 7401-7671q, 7542, 9601-9657, 11023, 11048.
II. Background
A. Clean Water Act
Congress adopted the Clean Water Act (CWA) to ``restore and
maintain the chemical, physical, and biological integrity of the
Nation's waters'' (Section 101(a), 33 U.S.C. 1251(a)). To achieve this
goal, the CWA prohibits the discharge of pollutants into navigable
waters except in compliance with the statute. The Clean Water Act
confronts the problem of water pollution on a number of different
fronts. Its primary reliance, however, is on establishing restrictions
on the types and amounts of pollutants discharged from various
industrial, commercial, and public sources of wastewater.
Direct dischargers must comply with effluent limitations in
National Pollutant Discharge Elimination System (``NPDES'') permits;
indirect dischargers must comply with pretreatment standards. These
limitations and standards are established by regulation for categories
of industrial dischargers and are based on the degree of control that
can be achieved using various levels of pollution control technology.
1. Best Practicable Control Technology Currently Available (BPT)--
Section 304(b)(1) of the CWA
Section 304(b)(1)(A) of the CWA requires EPA to identify effluent
reductions attainable through the application of, ``best practicable
control technology currently available for classes and categories of
point sources.'' Generally, EPA determines BPT effluent levels based
upon the average of the best existing performances by plants of various
sizes, ages, and unit processes within each industrial category or
subcategory. In industrial categories where present practices are
uniformly inadequate, however, EPA may determine that BPT requires
higher levels of control than any currently in place if the technology
to achieve those levels can be practicably applied (see A Legislative
History of the Federal Water Pollution Control Act Amendments of 1972,
U.S. Senate Committee of Public Works, Serial No. 93-1, January 1973,
p. 1468).
In addition, CWA Section 304(b)(1)(B) requires a cost assessment
for BPT limitations. In determining the BPT limits, EPA must consider
the total cost of treatment technologies in relation to the effluent
reduction benefits achieved. This inquiry does not limit EPA's broad
discretion to adopt BPT limitations that are achievable with available
technology unless the required additional reductions are ``wholly out
of proportion to the costs of achieving such marginal level of
reduction.'' (see Legislative History, op. cit. p. 170). Moreover, the
inquiry does not require the Agency to quantify benefits in monetary
terms (e.g., American Iron and Steel Institute v. EPA, 526 F. 2d 1027
(3rd Cir., 1975)).
In balancing costs against the benefits of effluent reduction, EPA
considers the volume and nature of expected discharges after
application of BPT, the general environmental effects of pollutants,
and the cost and economic impacts of the required level of pollution
control. In developing guidelines, the Act does not require
consideration of water quality problems attributable to particular
point sources, or water quality improvements in particular bodies of
water.
2. Best Available Technology Economically Achievable (BAT)--Section
304(b)(2) of the CWA
The CWA establishes BAT as a principal means of controlling the
discharge of toxic and non-conventional pollutants. In general, BAT
effluent limitations guidelines represent the best existing
economically achievable performance of direct discharging plants in the
industrial subcategory or category. The factors considered in assessing
BAT include the cost of achieving BAT effluent reductions, the age of
equipment and facilities involved, the processes employed, engineering
aspects of the control technology, 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 to these
factors. An additional statutory factor considered in setting BAT is
economic achievability. Generally, the achievability is determined on
the basis of the total cost to the industrial subcategory and the
overall effect of the rule on the industry's financial health. BAT
limitations may be based upon effluent reductions attainable through
changes in a facility's processes and operations. As with BPT, where
existing performance is uniformly inadequate, BAT may be based upon
technology transferred from a different subcategory within an industry
or from another industrial category. BAT may be based upon process
changes or internal controls, even when these technologies are not
common industry practice.
3. Best Conventional Pollutant Control Technology (BCT)--Section
304(b)(4) of the CWA
The 1977 amendments to the CWA required EPA to identify effluent
reduction levels for conventional pollutants associated with BCT
technology for discharges from existing industrial point sources. BCT
is not an additional limitation, but replaces Best Available Technology
(BAT) for control of conventional pollutants. In addition to other
factors specified in section 304(b)(4)(B), the CWA requires that EPA
establish BCT limitations after consideration of a two part ``cost-
reasonableness'' test. EPA explained its methodology for the
development of BCT limitations in July 1986 (51 FR 24974).
Section 304(a)(4) designates the following as conventional
pollutants: biochemical oxygen demand (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).
[[Page 6853]]
4. New Source Performance Standards (NSPS)--Section 306 of the CWA
NSPS reflect effluent reductions that are achievable based on the
best available demonstrated control technology. New facilities have the
opportunity to install the best and most efficient production processes
and wastewater treatment technologies. As a result, NSPS should
represent the greatest degree of effluent reduction attainable through
the application of the best available demonstrated control technology
for all pollutants (i.e., conventional, non-conventional, and priority
pollutants). In establishing NSPS, EPA is directed to take into
consideration the cost of achieving the effluent reduction and any non-
water quality environmental impacts and energy requirements.
5. Pretreatment Standards for Existing Sources (PSES)--Section 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 (POTWs). 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 implementing categorical pretreatment standards, are found at 40
CFR part 403. Those regulations contain a definition of pass through
that addresses localized rather than national instances of pass through
and establish pretreatment standards that apply to all non-domestic
dischargers. See 52 FR 1586, January 14, 1987.
6. Pretreatment Standards for New Sources (PSNS)--Section 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.
7. Best Management Practices (BMPs)
Sections 304(e), 308(a), 402(a), and 501(a) of the CWA authorize
the Administrator to prescribe BMPs as part of effluent limitations
guidelines and standards or as part of a permit. EPA's BMP regulations
are found at 40 CFR 122.44(k). Section 304(e) of the CWA authorizes EPA
to include BMPs in effluent limitations guidelines for certain toxic or
hazardous pollutants for the purpose of controlling ``plant site
runoff, spillage or leaks, sludge or waste disposal, and drainage from
raw material storage.'' Section 402(a)(1) and NPDES regulations (40 CFR
122.44(k)) also provide for best management practices to control or
abate the discharge of pollutants when numeric limitations and
standards are infeasible. In addition, section 402(a)(2), read in
concert with section 501(a), authorizes EPA to prescribe as wide a
range of permit conditions as the Administrator deems appropriate in
order to ensure compliance with applicable effluent limitations and
standards and such other requirements as the Administrator deems
appropriate.
8. CWA Section 304(m) Requirements
Section 304(m) of the CWA, added by the Water Quality Act of 1987,
requires EPA to establish schedules for: (1) Reviewing and revising
existing effluent limitations guidelines and standards; and (2)
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 effluent guidelines for
several industry categories, including the oil and gas extraction
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. Browner, Civ. No. 89-2980).
On January 31, 1992, the Court entered a consent decree (the ``304(m)
Decree''), which establishes schedules for, among other things, EPA's
proposal and promulgation of effluent guidelines for a number of point
source categories. The most recent Effluent Guidelines Plan was
published in the Federal Register on August 31, 2000 (65 FR 53008).
This plan requires, among other things, that EPA take final action
regarding the Synthetic-Based Drilling Fluids Guidelines by December
2000.
B. Pollution Prevention Act
The Pollution Prevention Act of 1990 (PPA) (42 U.S.C. 13101 et
seq., Public Law 101-508, November 5, 1990) ``declares it to be the
national policy of the United States that pollution should be prevented
or reduced whenever feasible; pollution that cannot be prevented should
be recycled in an environmentally safe manner, whenever feasible;
pollution that cannot be prevented or recycled should be treated in an
environmentally safe manner whenever feasible; and disposal or release
into the environment should be employed only as a last resort * * *''
(Sec. 6602; 42 U.S.C. 13101 (b)). In short, preventing pollution before
it is created is preferable to trying to manage, treat or dispose of it
after it is created. The PPA directs the Agency to, among other things,
``review regulations of the Agency prior and subsequent to their
proposal to determine their effect on source reduction'' (Sec. 6604; 42
U.S.C. 13103(b)(2)). EPA reviewed this effluent guideline for its
incorporation of pollution prevention.
According to the PPA, source reduction reduces the generation and
release of hazardous substances, pollutants, wastes, contaminants, or
residuals at the source, usually within a process. The term source
reduction ``include(s) equipment or technology modifications, process
or procedure modifications, reformulation or redesign of products,
substitution of raw materials, and improvements in housekeeping,
maintenance, training or inventory control. The term ``source
reduction'' does not include any practice which alters the physical,
chemical, or biological characteristics or the volume of a hazardous
substance, pollutant, or contaminant through a process or activity
which itself is not integral to or necessary for the production of a
product or the providing of a service.'' 42 U.S.C. 13102(5). In effect,
source reduction means reducing the amount of a pollutant that enters a
waste stream or that is otherwise released into the environment prior
to out-of-process recycling, treatment, or disposal.
In these final regulations, EPA supports pollution prevention
technology by encouraging the appropriate use of synthetic-based
drilling fluids (SBFs) based on the use of base fluid materials in
place of traditional: (1) Water-based drilling fluids (WBFs); and (2)
oil-based drilling fluids (OBFs) consisting of diesel oil/or and
mineral oil. The appropriate use of SBFs in place of WBFs will
generally lead to more efficient and faster drilling and a per well
reduction in non-water quality environmental impacts (including energy
requirements) and discharged pollutants. Use of SBFs may also lead to a
reduced demand for new drilling rigs and platforms and development well
drilling though the use directional and extended reach drilling.
Discharges from SBF-drilling operations have lower aqueous and
[[Page 6854]]
sediment toxicities, lower bioaccumulation potentials, and faster
biodegradation rates as compared to OBFs. In addition, polynuclear
aromatic hydrocarbons (PAHs), including those which are priority
pollutants, which are constituents in OBFs are not present in SBFs.
EPA considered a ``zero discharge'' requirement (i.e., BAT/NSPS
Option 3) for SBF-cuttings wastes and determined that under this
requirement most operators would decrease the use of SBFs in favor of
OBFs and WBFs due to lower OBF and WBF drilling fluid unit costs. EPA
concluded that a zero discharge requirement for SBF-cuttings and the
subsequent increased use of OBFs and WBFs would result in: (1)
Unacceptable non-water quality environmental impacts (NWQIs); and (2)
more pollutant loadings to the ocean due to operators switching from
SBFs to less efficient WBFs.
The appropriate use of SBF in place of OBF will generally shorten
the length of the drilling project and eliminate the need to barge to
shore or re-inject OBF-waste cuttings, thereby reducing NWQI such as
fuel use, air emissions, and land disposal of OBFs. The controlled
discharge option also eliminates the risk of OBF and OBF-cuttings
spills and cross-media contamination at land disposal operations.
Operators would be increasing the toxicity of their drilling fluids and
wastes by using OBFs in place of SBFs. As stated in April 2000 (65 FR
21557), EPA used SBF and OBF spill data in the final rule as a factor
in supporting a controlled discharge option. U.S. Department of
Interior, Minerals Management Service (MMS) spill data show that riser
disconnects in deep water drilling can release approximately 2,400
barrels of neat SBF and these incidences occur in deep water on average
two to three times per year due to riser failure (Docket No. W-98-26,
Record No. IV.B.a.3). Riser disconnects in the deep water are a
particular concern due to: (1) Increased riser tensioning; (2) deep
water technical requirements (e.g., riser verticality, increased use of
top drive systems, multiple flex joints in riser, placement of well
heads and upper casing sections in soft sea beds); and (3) deep water
ocean environments (e.g., uncharted eddy and loop currents) (Docket No.
W-98-26, Record No. IV.B.a.4; Record No. IV.B.a.5). Use of WBFs in
place of SBFs would also lead to: (1) An increase in NWQIs due to the
increased length of the drilling project; and (2) a per well increase
pollutants discharged due to poorer technical performance of WBFs. For
these primary reasons, EPA rejected the zero discharge option.
In addition, the technology controls in the final regulation are
based on a more efficient solids control technology to increase
recycling of SBF in the drilling operation. Increased SBF recycling
reduces the quantity of SBF required for drilling operations and the
quantity of SBF discharged with drill cuttings. A discussion of this
pollution prevention technology is contained in Section V.A of this
preamble and in the SBF Development Document.
C. Profile of Industry
1. Well Drilling Process Description
The SBF Development Document presents a thorough description of the
industry including drilling practices, solids control systems, and
waste disposal operations. The following summary is excerpted from that
technical document.
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 use a circularly rotating drill bit that grinds through
the earth's crust as it descends. Drilling fluids are pumped 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'' or simply ``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 and
stabilizing the well bore.
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 areas where drilling
fluids and drill cuttings are allowed to be discharged under the
current regulations, well depths range from approximately 4,000 to
12,000 feet deep, and it takes approximately 20 to 60 days to complete
drilling.
On the surface, the drilling fluid and drill cuttings undergo an
extensive separation process to remove fluid from the cuttings. The
fluid is then recycled into the system, and the cuttings become a waste
product. The drill cuttings retain a certain amount of the drilling
fluid that are discharged or disposed with the cuttings. Drill cuttings
are discharged by the shale shakers and other solids separation
equipment (e.g., decanting centrifuges, mud cleaners, cuttings dryers).
Drill cuttings are also cleaned out of the mud pits and from the solid
separation equipment during displacement of the drilling fluid system
(i.e., accumulated solids). 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.
In the relatively new area of ultra-deep water drilling (i.e.,
water depths greater than 3,000 feet), new drilling methods are
evolving which can significantly improve drilling efficiencies and
thereby reduce NWQIs (e.g., fuel, steel casing consumption, air
emissions) and the per well amount of pollutants discharged. Subsea
drilling fluid boosting, referred to as ``dual gradient drilling,'' is
one such new drilling technology. Dual gradient drilling is similar to
traditional rotary drilling methods as previously described with the
exception that the drilling fluid is energized or boosted by use of a
pump at or near the seafloor. By boosting the drilling fluid, the
adverse effect on the wellbore caused by the drilling fluid pressure
from the seafloor to the surface is eliminated, thereby allowing wells
to be drilled with as much as a 50% reduction in the number of casing
strings generally required to line the well wall. As a result of the
reduced number of casing strings, dual gradient wells can be drilled
almost one-third faster and with smaller hole sizes than conventional
deep water drilling. Smaller hole sizes and faster drilling translate
into fewer pollutants being discharged to the ocean and fewer NWQI.
Dual gradient drilling technology can also potentially eliminate or
reduce the amount of whole drilling fluid released to the environment
during an inadvertent riser disconnect. Finally, dual gradient drilling
technology can greatly reduce the potential release of drilling fluid
when drilling through shallow sand intervals (e.g., shallow water flow)
(Docket No. W-98-26, Record No. IV.B.a.6).
Some dual gradient drilling systems require the separation of the
largest cuttings (e.g., larger than approximately \1/4\ inch) at the
seafloor since these cuttings may interfere with the rotatory action of
subsea pumps (e.g., electrical
[[Page 6855]]
submersible pumps). The larger cuttings are routed at the seafloor to a
venturi action pump (with no moving parts), mixed with seawater, and
pumped to a cuttings discharge hose at the seafloor within a 300 foot
radius of the well site. The hose is perforated on the last 50 ft of
its length to maximize the spread of cuttings. The action of pumping
cuttings with seawater can be expected to have some cleaning and
dispersion effect. A remotely operated vehicle (ROV) can also be used
to reposition the subsea discharge hose to maximize cuttings dispersal.
Representative samples of drill cuttings discharged at the seafloor can
be transported to the surface by a ROV for purposes of monitoring. The
drilling fluid, which is boosted at the seafloor and transports most of
the drill cuttings (e.g., 95-98% of total cuttings generated) back to
the surface, is processed as described in the general rotary drilling
methods described above in this section.
A commercial potential determination is made at the completion of
rotary drilling (i.e., once the target oil or natural gas formations
have been reached). The well is then made ready for production by a
process termed ``completion.'' Completion involves cleaning the well to
remove drilling fluids and debris, perforating the casing that lines
the producing formation, inserting production tubing to transport the
hydrocarbon fluids to the surface, and installing the surface wellhead.
The well is then ready for production (i.e., actual extraction of
hydrocarbons).
2. Location and Activity
This rule establishes effluent limitations guidelines and standards
that control discharges of SBF and SBF-cuttings throughout the Offshore
subcategory beyond three miles from shore, except for Offshore Alaska
where no three mile restriction applies. This rule prohibits discharge
of SBF and SBF-cuttings in Upper (Coastal Subcategory) Cook Inlet,
Alaska, unless operators meet criteria demonstrating that they are
unable to: (1) Box and store their cuttings on-site for zero discharge
cuttings transfer operations (i.e., haul to shore for land disposal or
re-injection at another rig or platform); or (2) re-inject their SBF-
cuttings on-site. When Coastal Cook Inlet, AK, operators demonstrate to
the NPDES controlling authority that they are unable to achieve zero
discharge of their SBF-cuttings, they may discharge their SBF-cuttings
under the same controls as exist for SBF-cuttings discharges in
Offshore waters. Criteria for establishing when operators cannot
achieve zero discharge are established in the final regulation. SBF-
cuttings discharged in Offshore Cook Inlet, Alaska, are controlled in
the same manner as other SBF-cuttings in other Offshore waters. This
rule does not amend the requirements for zero discharge of drilling
fluids and drill cuttings where they have already been prohibited from
discharge.
Drilling is currently active in three regions: (1) The offshore
waters beyond three miles from shore in the Gulf of Mexico (GOM); (2)
offshore waters beyond three miles from shore in California; and (3)
Cook Inlet, Alaska. Most drilling activity occurs in the GOM, where
1,302 wells were drilled in 1997, compared to 28 wells drilled in
California and 7 wells drilled in Cook Inlet. In the GOM, over the last
few years, there has been high growth in the number of wells drilled in
deep water (e.g., water depths greater than 1,000 feet). For example,
in 1995, 84 wells were drilled in deep water, comprising 8.6% of all
GOM wells drilled that year. By 1997, that number increased to 173 deep
water wells drilled and comprised over 13% of all GOM wells drilled.
Most recent 1999 data show that this trend is continuing as over 15% of
all GOM wells drilled were in deep water. The increased activity in
deep water increases the usefulness of SBFs. Operators drilling in deep
water cite the following factors for selecting SBFs over WBFs and OBFs:
(1) Potential for riser disconnect (i.e., inadvertent releases of
drilling fluid) in floating drill ships, which favors SBF over OBF; (2)
higher daily drilling cost which more easily justifies use of more
expensive SBFs over WBFs; and (3) greater distance to barge drilling
wastes that may not be discharged (i.e., OBFs, WBFs that fail the SPP
Toxicity Test as currently required by EPA in Appendix 2 to Subpart A
of 40 CFR part 435).
3. Drilling Wastestreams
Drilling fluids and drill cuttings are a major source of waste from
exploratory and development well drilling operations. This final
regulation establishes limitations for both the drilling fluid and the
drill cuttings wastestream when SBFs are used. All other wastestreams
and drilling fluids
(e.g., WBFs, OBFs) already have limitations; those limitations are
outside the scope of this rule. The characteristics of both drilling
fluids and drill cuttings wastestreams are summarized in Section V.A of
this preamble. A more detailed discussion of the origins and
characteristics of these wastes is also included in the SBF Development
Document.
D. Proposed Rule
On February 3, 1999 (64 FR 5488), EPA published proposed effluent
limitations guidelines for the discharge of SBF drilling fluids and
drill cuttings into waters of the United States by existing and new
facilities in the oil and gas extraction point source category.
EPA received comments on many aspects of the proposal. The majority
of comments related to: (1) The proposed analytical test methods for
stock and discharge limitations; (2) equipment used to set BAT and NSPS
cuttings retention limitations; (3) Best Management Practices (BMPs)
and their use to control small volume spills and releases of SBF; (4)
the proposal's engineering and economic modeling parameters; and (5)
procedural and definition issues. EPA evaluated all of these issues
based on additional information collected by EPA or received during the
comment period. EPA then discussed the results of these evaluations in
a Notice of Data Availability which is discussed below.
E. Notice of Data Availability
On April 21, 2000 (65 FR 21548), EPA published a Notice of Data
Availability (NODA) to present a summary of new data received in
comments on the proposed rule or collected by EPA following publication
of the proposal. In the April 2000 NODA, EPA discussed the major issues
and presented several revised modeling and alternative approaches to
address these issues. EPA solicited comment on the data collected since
proposal and on the revised modeling and alternative approaches to
manage SBF discharges.
III. Summary of Data and Information Received in Response to the
Notice of Data Availability
The April 2000 NODA summarized the data and information received by
EPA in response to the February 1999 proposal and information received
before the April 2000 NODA. This section describes the data received by
EPA in response to the April 2000 NODA.
A. Pollutant Loading and Numeric Limit Analyses
1. SBF Retention on Cuttings
SBF retention on cuttings (ROC) data quantify the amount of SBF
retained on cuttings (mass of SBF/mass of wet cuttings, expressed as a
percentage). Lower ROC values indicate less SBF retained on cuttings.
EPA uses ROC data, along with other engineering factors (e.g.,
installation requirements, fluid rheology) to evaluate the
[[Page 6856]]
performance of various solids control technologies.
In response to the February 1999 proposal, industry submitted data
for SBF ROC from 36 wells. EPA determined that 16 files were complete
and accurate, and these data were presented in the April 2000 NODA. EPA
rejected six files due to incomplete reporting. EPA received 14 files
too late for inclusion in the April 2000 NODA analyses.
In response to the April 2000 NODA, EPA received and evaluated ROC
data from an additional 79 SBF wells: the 14 received after the
February 1999 proposal comment period; 27 additional sets received
during the April 2000 NODA comment period; and 38 received after the
April 2000 NODA comment period. EPA determined that data from 49 of
these 79 wells were complete for inclusion in the final rule analyses.
Therefore, EPA used data from 65 wells to determine the ROC performance
of the various solids control technologies. The collection, engineering
review, and extraction of data from these files are described in the
SBF Development Document.
EPA revised the average ROC values of various solids control
technologies based on the final ROC data. These revised average ROC
values were combined to yield the average ROC value for the following
three SBF-cuttings technology options: (1) BAT/NSPS Option 1 is based
on the use of shale shakes, cuttings dryer, fines removal unit, and
discharges from the cuttings dryer and fines removal unit and has a
long-term average ROC value of 4.03%; (2) BAT/NSPS Option 2 is based on
the use of shale shakes, cuttings dryer, and fines removal unit, and
one discharge from the cuttings dryer, and has a long-term average ROC
value of 3.82%; and (3) BAT/NSPS Option 3 is based on the use of shale
shakes, cuttings boxes, barges, and zero discharge land disposal and
offshore re-injection and has a long-term average ROC value of 10.2%.
In addition, using the ROC data, EPA developed a BAT limitation and
standard controlling the base fluid retained on cuttings for drilling
fluids with the environmental performance of esters (e.g.,
biodegradation, sediment toxicity). EPA developed this option to
provide operators an incentive to use ester-based SBFs and has a long-
term average ROC value of 4.8%. EPA used the ROC data to establish a
BAT limitation and a NSPS on base fluid retained on cuttings. The base
fluid retained on cuttings limitation and standard both incorporate the
variability of solids control efficiencies and are higher than the long
term average.
2. Days to Drill
EPA uses the number of days to drill the SBF interval, for all four
model wells, as an input parameter in the NWQI and cost analysis. EPA
extracted relevant data from each of the 65 wells identified above to
estimate the number of days to drill each of the four model well SBF
intervals (Docket No. W-98-26, Record No. IV.B.a.7). The revised
numbers of days required to drill the SBF model wells are based on a
revised average rate of SBF-cuttings generation (i.e., 108.7 bbls wet
cuttings/day). The revised numbers of days required to drill the SBF
model wells are: (1) 5.2 days for shallow-water development wells
(SWD); (2) 10.9 days for shallow-water exploratory wells (SWE); (3) 7.9
days for deep-water development wells (DWD); and (4) 17.5 days for
deep-water exploratory wells (DWE).
3. Well Count Projections Over Next Five Years
EPA revised well count projections for Offshore GOM, Offshore
California, and Cook Inlet, AK, based on information submitted by
industry (Docket No. W-98-26, Record No. IV.B.a.9; Record No.
IV.B.a.10; Record No. IV.B.a.11). The revised annual well counts are
1,047 shallow water wells and 138 deep water wells in Offshore GOM; 7
shallow water wells and no deep water wells in Offshore California; and
6 shallow water wells and no deep water wells in Cook Inlet, AK. These
revised well counts are not significantly different from the well
counts used in the February 1999 proposal and April 2000 NODA (i.e.,
see SBF Proposal Development Document (EPA-821-B-98-021), Table IV-2:
1,022 shallow water wells and 139 deep water wells across the GOM,
Offshore California, and Cook Inlet, AK).
Industry only provided the well counts in terms of shallow water
versus deep water wells. EPA further divided the revised well counts
into development and exploratory well category counts for estimating
pollutant loadings, compliance costs, and NWQIs. EPA performed this
allocation using prior well count data from the April 2000 NODA. EPA
derived percentages of development versus exploratory wells for both
shallow water well types and deep water well types. EPA then applied
these percentages to the revised aggregated shallow water and deep
water well counts provided by industry. EPA also collected additional
washout rates for WBF and SBF drilling.
EPA also revised well count projections to reflect enhanced
directional drilling capabilities when using SBF. EPA received
information that SBF directional drilling can reduce the number of
wells required to drill a development well project. Specifically,
industry stated that SBF development drilling can generally reduce the
drilled footage required for full development of a typical reservoir by
one-third as compared with WBF drilling (Docket No. W-98-26, Record No.
IV.B.a.9). EPA has included this consideration by reducing the footage
drilled by one-third for WBF development wells projected to convert
from WBF to SBF under the two controlled discharge options.
4. Current and Projected OBF, WBF, and SBF Use Ratios
For the February 1999 proposal and April 2000 NODA, EPA estimated
that 80% of the average annual GOM wells are drilled using WBF
exclusively; 10% are drilled with SBF; and 10% are drilled with OBF.
EPA also included in well counts estimates of operators converting from
OBF to SBF or SBF to OBF under each of the SBF-cuttings controlled
discharge options.
For the final rule, EPA revised the relative frequency of use
between WBF, OBF, and SBF under the two discharge options and the zero
discharge option based on data submitted by industry (Docket No. W-98-
26, Record No. IV.B.a.9; Record No. IV.B.a.10; Record No. IV.B.a.11).
Industry supplied this information to EPA in several formats. EPA used
the most reliable information (e.g., the actual well count data for
WBF, OBF, and SBF wells over a period of three years) to estimate
drilling fluid use under each of the SBF-cuttings control options (see
SBF Development Document).
EPA believes that some operators would switch from WBFs to SBFs for
certain wells due to the increased efficiency of SBF drilling. While no
good industry average statistics exist, it is generally considered that
SBFs reduce overall drilling time by 50% (e.g., if a well took 60 days
to drill with WBF, the same well should be able to be drilled with SBF
in 30 days) (Docket No. W-98-26, Record No. IV.B.a.9; Record No.
IV.B.a.10; Record No. IV.B.a.11). Reducing drilling time generally
reduces drilling costs. However, not all drilling operators will switch
from WBFs to SBF due to a variety of other factors, (e.g., WBFs are
less expensive (per barrel) than SBFs, potential for lost circulation
downhole).
Additionally, EPA believes that under the SBF-cuttings zero
discharge option, not all operators would switch from
[[Page 6857]]
SBFs to OBFs but that some operators would switch to WBFs. Some
drilling operations require the technical performance of non-aqueous
drilling fluids and operators must select either an OBF or SBF.
Therefore, for these drilling operations, operators would select OBFs
in place of SBF under the SBF-cuttings zero discharge option as OBFs
are less expensive (per barrel) than SBFs. However, some drilling
operations could use either WBFs or oleaginous drilling fluids such as
OBFs, enhanced mineral oil based drilling fluids, or SBFs. Depending on
a variety of site specific factors (e.g., formation characteristics,
directional drilling requirements, torque and drag requirements),
operators may select WBFs in lieu of SBFs or OBFs under the SBF-
cuttings zero discharge option.
5. Waste Volumes and Characteristics
EPA collected additional data to identify the volumes and
characteristics of WBF discharges. This additional data more adequately
describes the total amount of pollutants loadings and NWQI under each
of the three SBF-cuttings management options. For example, under the
SBF zero discharge option (BAT/NSPS Option 3) operators would more
likely choose WBF and OBF over SBF due primarily to the relatively
higher unit cost of SBF.
Different pollutant loadings and NWQI are expected for WBF as
compared with either OBF or SBF wells based on differences in washout
and length of drilling time. EPA anticipates a reduction in cuttings
waste volume when comparing SBF-drilling to WBF-drilling based on
greater hole washout (i.e., enlargement) in WBF drilling. Industry
estimated that WBF washout percentages vary between 25% and 75%, with
45% being an acceptable average and confirmed EPA's SBF and OBF washout
percentage of 7.5% as appropriate (Docket No. W-98-26, Record No.
IV.B.a.9).
For the final rule, EPA also estimated that the barite used in SBF
drilling is nearly pure barium sulfate (i.e., BaSO4) and, by
gravimetric analysis, calculated the weight percentage of barium in
barite as 58.8%.
B. Compliance Costs Analyses
1. Equipment Installation and Downtime
For the April 2000 NODA, projected compliance costs for all options
included equipment installation and downtime for each SBF well drilled.
After further review of ROC data wells (see Section III.A), EPA
modified this parameter in the final analyses to reflect current
practice of drilling multiple wells per year for any one equipment
installation (Docket No. W-98-26, Record No. IV.B.a.9). EPA reviewed
the ROC well data for the frequency of multiple wells on specified
structures. EPA used the resulting well-per-structure analysis to
adjust projected annual SBF compliance costs by including the
consideration of drilling more than one SBF well per equipment
installation per year. EPA estimated that 2.2 development wells per
structure and 1.6 exploratory wells per structure are current industry
practice, based on industry-submitted data (see SBF Development
Document).
EPA received information on the ability of operators to install
cuttings dryers (e.g., vertical or horizontal centrifuges, squeeze
press mud recovery units, High-G linear shakers) on existing GOM rigs
(Docket No. W-98-26, Record No. IV.B.b.33). While some industry sources
filed timely comments alleging that some rigs could not accommodate
additional solids control equipment, in late comments, industry
provided data concerning the number of GOM rigs in operation which are
not capable of having a cuttings dryer system installed due to either
rig space and/or rig design without prohibitive costs or rig
modifications.
EPA also received information on a new cuttings containment,
handling, and transfer equipment system. The new system is designed to
eliminate the need to use cuttings boxes to handle cuttings. EPA
received information from one operator that recently field tested the
cuttings transfer system on one 12\1/4\ inch well section in the North
Sea. The operator contained 100% of the cuttings on a rig (Alba) with
limited deck space. Cuttings were handled in bulk below deck and pumped
directly onto a waiting vessel for eventual land disposal. The operator
estimated that use of the new cuttings transfer system eliminated
hundreds of crane lifts and manual handling issues and thereby improved
worker safety.
2. Current Drilling Fluid Costs
In response to the April 2000 NODA, EPA revised unit costs of WBF,
OBF, and SBF. Based on industry data, EPA used the WBF unit cost of $45
per barrel for the final rule. The February 1999 Proposal and April
2000 NODA used OBF and SBF unit costs of $75 and $200 per barrel of
drilling fluid, respectively. Industry data indicates a range of OBF
unit costs from $70-$90 per barrel and EPA used the OBF unit cost of
$79 per barrel for the final rule. EPA estimates that SBF unit costs
will remain between $160 to $300 per barrel of drilling fluid over the
next few years. EPA used an SBF unit cost of $221 per barrel of
drilling fluid for the final rule based on the most frequently used SBF
in the offshore market.
3. Cost Savings of SBF Use as Compared With WBF Use
EPA revised its compliance costs to include the following factors:
(1) The cost savings associated with increased rate of penetration when
using SBF as compared to WBF; and (2) the cost of lost WBFs that are
discharged while drilling. EPA also examined, but did not include in
its final compliance cost impacts, the costs associated with projected
failures of a fraction of WBF wells to meet sheen or toxicity
limitations, including costs of meeting zero discharge from these
wells. EPA used this data to examine compliance costs impacts if
operators switch from SBF to WBF drilling, or vice versa.
EPA requested data from industry on rate of penetration (ROP) for
WBF operations as compared to SBF operations. Industry stated that ROP
values of 300 feet per hour for SBF (and OBF) operations and 150 feet
per hour for WBF are reasonable averages. However, using these values
over an entire well was not recommended ``due to the large number of
variables'' (Docket No. W-98-26, Record No. IV.B.a.9). Industry's
information further states that a generally-accepted estimate is that
``SBFs reduce overall drilling time by 50%'' (Docket No. W-98-26,
Record No. IV.B.a.9).
4. Construction Cost Index
EPA used the Construction Cost Index (CCI) from the Engineering
News and Record (see http://www.enr.com/cost/costcci.asp) to reflect
costs in 1999 dollars rather than 1998 dollars as was used for the
April 2000 NODA. EPA used a CCI factor of 1.108 to reflect 1999 dollars
and a base year of 1995.
C. Economic Impacts Analyses
For the final rule, EPA obtained and used MMS data on drilling
through 1999 to identify any new firms operating in the offshore GOM
and determine which firms were involved in deep water drilling
operations. EPA identified 17 additional firms newly drilling in the
GOM, of which 2 were identified as drilling in deep water. Of the new
firms, 7 were identified as or assumed to be (for lack of data) small
entities. One of these seven small firms was identified as a small
entity drilling in deep water. This latter firm drilled two wells in
the deep water in 1999.
EPA collected 1999 financial information on number of employees,
[[Page 6858]]
assets, equity, revenues, net income, return on assets, return on
equity, and profit margin for the publicly held, newly identified
firms. EPA also updated financial information for the publicly held
firms identified in February 1999 proposal SBF Economic Analysis (EPA-
821-B-98-020).
EPA also collected information on 13 GOM onshore sites where
offshore oil and gas drilling waste is handled or disposed. This
information consists of precise geographical location, amount of waste
handled annually, and site capacity. This information was provided to
EPA Region 6 for use in its environmental justice (EJ) computer model
to screen for sites (i.e., Tier 1 analysis) where disposal of
additional drilling wastes under a zero discharge option might have
environmental justice implications. EPA Tier 1 analyses identified that
five of the thirteen onshore facilities warranted additional review.
D. Water Quality Impact and Human Health Analyses
In response to April 2000 NODA comments and information, EPA
revised the water quality and human health analyses for the final rule
based on: (1) Information on seabed surveys; (2) revised fish
consumption rates; (3) information on Alaska state water quality
standards; and (4) revised ROC data which affect EPA modeling of water
quality, sediment quality, and human health impacts.
1. Seabed Surveys
EPA received public comments regarding the impact of SBF discharges
on the benthic environment. Several seabed surveys were submitted to
EPA together with the public comments. Information from two comments
contained specific seabed survey data on sediment SBF concentrations
after discharge of SBF cuttings. EPA included additional data from six
wells in the calculation of mean SBF sediment concentration (at 100
meters from the modeled discharge) used in the water quality analysis.
The mean SBF sediment concentration changed from 14,741 mg/kg as
published in the April 2000 NODA to 9,718 mg/kg for modeled Gulf of
Mexico wells and from 8,655 mg/kg to 13,052 mg/kg for wells modeled in
Offshore California and Cook Inlet, Alaska.
EPA also received information on the on-going joint Industry/MMS
GOM seabed survey. The Industry/MMS workgroup completed the first two
cruises of the four cruise study in time for EPA's consideration for
this final rule. Cruise 1 was a physical survey of 10 GOM shelf
locations, with the objective of detection and delineation of cuttings
piles using physical techniques. Cruise 2 was to scout and screen the
final 5 shelf and 3 deep water GOM wells chosen for the definitive
study where SBF were used. The SBF-cuttings discharges included either
internal olefins or LAO/ester blends. Both cruises did not detect any
large mounds of cuttings under any of the rigs or platforms. Remotely
operated vehicles (ROV) using video cameras and side-scanning sonar
were used to conduct the physical investigations on the seabed. Video
investigations only detected small cuttings clumps (6") around the base
of some of the facilities and 1" thick cuttings accumulations on
facility horizontal cross members. Outside of a 50-100' radius from the
facility, no visible cuttings accumulations (large or small) were
detected at any of the facility survey sites.
Finally, EPA received a report prepared for the MMS which provided
a review of the scientific literature and seabed surveys to determine
the environmental impacts of SBFs (Docket No. W-98-26, Record No.
IV.F.1). The literature report confirms EPA's position that benthic
communities will recover as SBF concentrations in sediments decrease
and sediment oxygen concentrations increase. The report also confirms
EPA's position that within three to five years of cessation of SBF-
cuttings discharges, concentrations of SBFs in sediments will have
fallen to low enough levels and oxygen concentrations will have
increased enough throughout the previously affected area that complete
recovery will be possible.
2. Fish Consumption Rates
EPA revised the fish consumption rates for use in environmental
assessment analyses. The consumption rates vary depending on the fish
habitat location (i.e., freshwater, estuarine, and marine). EPA used
the marine only fish consumption rate for the finfish consumption
health risk analysis for the Gulf of Mexico and Offshore California.
EPA used the estuarine/marine consumption rate for the Cook Inlet,
Alaska analysis. EPA used the estuarine/marine consumption rate for all
regions in the shrimp consumption health risk analysis.
EPA also conducted an investigation into the environmental factors
affecting Native subsistence foods in Cook Inlet. EPA has incorporated
relevant information from this investigation into the SBF Environmental
Assessment.
3. State Water Quality Standards
EPA evaluated the potential decrease of water quality from the
regulatory discharge options and compared the pollutant concentrations
to recommended Federal water quality criteria. For discharges occurring
in Cook Inlet, Alaska, EPA also compared the receiving water quality to
Alaska state water quality standards. EPA used the updated Alaska state
standards for the water quality analysis for Cook Inlet, Alaska.
E. Non-Water Quality Environmental Impact Analyses
EPA received additional data affecting the NWQI analyses in
response to the April 2000 NODA. These data include additional
information on retention on cuttings and information regarding offshore
injection and onshore disposal practices for each of the three
geographical areas: Gulf of Mexico, Offshore California, and Cook
Inlet, Alaska.
EPA revised the average SBF retention on cuttings for the discharge
options based on additional ROC data. Revisions in ROC data affect the
volume of SBF-cuttings generated. Consequently, EPA revised the amount
of SBF-cuttings that will need to be treated under the two SBF-cuttings
controlled discharge options (e.g., BAT/NSPS Options 1 and 2). EPA also
revised: (1) The amount of SBF-fines that will need to be re-injected
on-site or hauled to shore for disposal under one of the SBF-cuttings
controlled discharge option (e.g., BAT/NSPS Option 2); and (2) the
amount of SBF-fines and SBF-cuttings re-injected on-site or hauled to
shore for disposal under the zero discharge option (BAT/NSPS Option 3).
EPA received additional SBF well interval data which was used to
re-calculate the number of days to drill the model SBF wells (see
Section III.B.). For the NWQI analyses, the number of days to drill the
model wells serves as the basis for estimating the length of time
equipment will be used to either treat the cuttings before discharge or
the hauling requirements under the zero discharge option. The EPA NWQI
models estimate that air emissions and fuel use rates increase when the
time required to complete a model well also increases.
EPA obtained information regarding the current practice of zero
discharge disposal for each of three geographic areas, Gulf of Mexico,
Offshore California, and Cook Inlet, Alaska (see Section IV.D). Current
practice indicates that most of the waste generated in the Gulf of
Mexico and Offshore California
[[Page 6859]]
and brought to shore is injected onshore, whereas all of the waste
currently generated in Cook Inlet is injected offshore at the drilling
site or at a near-by Class II Underground Injection Control (UIC)
disposal well. EPA also received from an on-shore injection facility
specific equipment information, including the cuttings injection rate
and cuttings grinding and injection equipment power requirements and
fuel rates (Docket No. W-98-26, Record No. IV.D.2).
Industry provided EPA with information regarding SBF use (see
Section III.A). One operator (Unocal) stated that it is starting to use
SBF to drill the entire well and not just intervals in which WBFs
present problems because drilling time can be significantly reduced.
EPA incorporated this information into the NWQI analyses by estimating
the reduction of impacts when using SBFs instead of WBFs. EPA also
received during the April 2000 NODA comment period information related
to the average increase in drilling time (1.5 days) in order to comply
with zero discharge (Docket No. W-98-26, Record No. IV.A.a.3).
F. Compliance Analytical Methods
EPA completed additional studies in response to the April 2000 NODA
to support the development of analytical methods for determining
sediment toxicity, biodegradation, and oil retention on cuttings. For
sediment toxicity and biodegradation, EPA focused specifically on
optimizing test conditions (e.g., test duration, sediment composition),
discriminatory power, reproducibility, reliability, and practicality.
EPA's sediment toxicity study provided toxicity data for both pure base
fluids and standard mud formulations of these base fluids. EPA's
biodegradation study evaluated the degradation of pure base fluids as
determined by the solid phase test. For oil retention on cuttings, EPA
conducted studies to verify and document the sensitivity of the retort
test method.
During this same time period, industry sponsored Synthetic Based
Muds Research Consortium (SBMRC) conducted parallel studies on the same
three parameters (i.e., sediment toxicity, biodegradation, and base
fluid retention on cuttings). For sediment toxicity, industry provided
extensive data comparing a 4-day versus a 10-day test duration, natural
versus synthetic sediments, as well as toxicity data on both pure base
fluids and mud formulations of these base fluids. For biodegradation,
industry submitted results from the closed bottle and respirometry
tests for biodegradation in addition to the solid phase test. For oil
retention on cuttings, Industry and EPA conducted rig-based method
detection limit studies.
IV. Summary of Revisions Based on Notice of Data Availability
Comments
A summary of significant revisions to the analyses made by EPA in
response to the February 1999 proposal is provided in the April 2000
NODA (see 65 FR 21549, Sections III and IV). This section describes the
revisions to the analyses since publication of the April 2000 NODA.
A. Pollutant Loading Analyses
1. Loadings for Water-Based Drilling Fluids and Cuttings
For the final rule, EPA included the pollutant reductions (or
increases) of the technology options based on operators switching from
OBFs or WBFs to SBFs (or vice versa) and used data contained in the
Offshore Development Document (EPA-821-R-93-003). Waste volume and/or
pollutant loading data, on use of OBFs and WBFs presented in the
Offshore Development Document, were expressed on a ``per bbl,'' ``per
well,'' or a ``per day'' basis. Data from the Offshore rule record
included: (1) WBF composition; (2) waste volumes for WBFs, OBFs, and
associated cuttings; (3) the frequency of mineral oil use in WBF
operations; and (4) the expected permit limitation failure rates
(primarily for toxicity) on mineral oil fluids resulting in the
requirement to haul or inject these wastes). These data then were
applied to the current, revised well count projections and/or projected
waste volumes to estimate discharge option loadings and the amount of
OBFs, WBFs, and associated cuttings that require zero discharge under
existing regulations (e.g., OBFs containing diesel oil, WBFs that fail
the SPP Toxicity Test). The Offshore Development Document provided
information relevant to the inclusion of WBFs in the final analyses
including: (1) Frequency of WBFs that failed permit limitations (Tables
XI-10 and XI-7); (2) the composition of WBFs (Tables XI-3 and XI-6);
(3) mineral oil composition (Table XI-5); and (4) the composition of
cuttings from WBF (Section XI.3.4).
Industry-wide, regional, and total loadings were calculated for the
loadings analyses for this final rule from the revised well counts
provided by industry (Docket No. W-98-26, Record No. IV.B.a.9; Record
No. IV.B.a.10; Record No. IV.B.a.11) combined with composition and
estimated discharge volumes for WBFs (Offshore Development Document,
Table XI-2).
In the final loadings analyses, EPA also corrected an error in the
loading model used for the April 2000 NODA analyses. The error related
to how EPA estimated the volume of fines from the fines removal unit
captured and not discharged under BAT/NSPS Option 2. The volume of
fines is based on many factors including the hole size, washout, and
the percentage of the total wet cuttings produced from the solids
control system that are fines. EPA incorrectly used the volume of dry
cuttings per model well in the April 2000 NODA loading model to
estimate the volume of fines generated from the BAT/NSPS Option 2
solids control system. The final loadings model correctly uses the
volume of wet cuttings per model well to estimate the volume of fines
generated from the BAT/NSPS Option 2 solids control system. The
correction of the error had the effect of increasing the amount of
fines captured for zero discharge under BAT/NSPS Option 2.
2. Drilling Fluid and Cuttings Composition and Density
The density of drilling wastes hauled in California was revised
from 704 to 716 pounds per barrel to reflect the current density
derived from the weight and volume data in the revised loadings model.
This results in a change in the unit cost to haul waste in California
to $12.53 and $5.89 per barrel for disposal and handling costs,
respectively.
3. Days to Drill
EPA revised the number of drilling days based on data submitted in
response to the April 2000 NODA for each of the four model well types.
The number of drilling days input parameter affects NWQI and compliance
costs (e.g., equipment rental costs).
4. Directional Drilling
EPA also received additional data concerning the performance of SBF
versus WBF for directional drilling operations (Docket No. W-98-26,
Record No. IV.B.a.9). EPA used this information, the reduced number of
wells and total footage of SBF-drilled development wells, to estimate
pollutant loading reductions resulting from WBF to SBF conversions. For
each of the two SBF-cuttings controlled discharge options (i.e., BAT/
NSPS Option 1 and 2), this revision reduced the annual sum total of
discharged WBF and WBF-cuttings.
[[Page 6860]]
B. Compliance Cost Analysis
1. Costs of WBF
As stated above, EPA modified the cost analysis for the final rule
to include WBF cost factors. The WBF cost factors that EPA considered
include: (1) The cost of discharged WBFs and WBF associated with
cuttings discharged onsite; (2) the projected occurrence of mineral oil
spots and/or lubrication and the projected failure rate of these
mineral oil-amended fluids to meet permit limitations on toxicity and
subsequent requirement to re-inject these materials down hole or haul
them for onshore disposal; and (3) the rig costs associated with
increases or decreases of drilling time related to WBF-to-SBF or SBF-
to-WBF conversions over the projected interval of SBF use.
The volumes of discharged WBF and associated cuttings were
estimated on a per well basis from data contained in the Offshore
Development Document (EPA-821-R-93-003) for Gulf of Mexico, California,
and Cook Inlet, AK wells. A weighted average discharge volume for each
region, based on volumes projected for shallow wells and deep wells and
the projected number of wells for each, was derived to estimate the
volume of fluids and cuttings discharged onsite, per well, from WBF
operations. (Note: In the Offshore Development Document ``shallow'' and
``deep'' refer to well depth, and are not the same as ``shallow'' water
and ``deep'' water wells which refer to water depth in this final
rule.) The volume of adhering WBF on discharged cuttings, as contained
in the Offshore Development Document, was estimated at 5% of the total
cuttings volume. The costs for these discharged WBFs were then
calculated from a per barrel estimate of average WBF cost. These per
well costs were then applied to the well count data in this final rule
to derive aggregate regional and total costs. Also, to assess lost
fluid costs over the projected SBF drilling interval, for the zero
discharge option, the average discharge volumes per well were
recalculated as average discharge volumes per day, based on the assumed
number of days (i.e., 20 days) used in the Offshore Development
Document for drilling WBF wells.
The projected incidences of WBF with mineral oil spots, mineral oil
lubrication, or both mineral oil spot and lubrication were based on the
Offshore Development Document estimates of the percentages of projected
wells in each region, projected shallow water versus deep water wells,
and the projected incidence of spotting and lubrication. These
percentages were then applied to current well count data for this final
rule. EPA used the Offshore Development Document rates of failure
(i.e., exceeding permit toxicity limitations) to project the current
number of wells that would require onsite injection or onshore disposal
of mineral oil-amended WBF, and their disposal volumes were calculated
from per well volume estimates for WBF wells.
The effect of WBF-to-SBF conversion (anticipated under the
discharge options) and SBF-to-WBF conversion (anticipated under the
zero discharge option) were derived from the estimated duration (in
days) of the SBF-drilled interval. The projected number of drilling
days was increased by a factor of 2 for each WBF model well to derive
the projected number of drilling days that would be required if WBFs
were used in place of SBFs. The incremental drilling time was used to
estimate compliance costs (e.g., increased rig costs) associated with
SBF-to-WBF conversions.
2. Equipment Installation and Downtime
In the April 2000 NODA, EPA estimated that each SBF well incurred
cuttings dryer installation and downtime costs. EPA revised the number
of SBF wells drilled per cuttings dryer equipment installation per year
based on industry-supplied ROC data (see Section III.B.1). EPA
concluded that operators are drilling multiple wells per year with the
same cuttings dryer equipment installation. Consequently, EPA reduced
the number of cuttings dryer equipment installations required to drill
the annual number of SBF wells. For development wells, the average
number of SBF wells drilled per cuttings dryer equipment installation
per year is 2.2. For exploration wells, the average number of SBF wells
drilled per cuttings dryer equipment installation per year is 1.6. EPA
incorporated these factors into the compliance costs estimates and
these factors reduced the overall cuttings dryer equipment installation
and downtime costs for the industry.
3. Proportion of Hauled Versus Injected Wastes
EPA estimated in the April 2000 NODA that 80% of drilling
operations in the GOM, Offshore California, and Cook Inlet, Alaska,
haul waste onshore with the remaining 20% re-injecting these wastes
onsite. EPA used these proportions to weight the average cost of
complying with zero discharge (i.e., BAT/NSPS Option 3). EPA revised
these proportions based on additional information received in response
to the April 2000 NODA (see Section IV.E below) and updated the
compliance cost and NWQI models.
4. OBF and WBF Conversion to SBF
EPA revised its compliance cost model to incorporate the effect of
operators switching from one type of drilling fluid to another under
each of the three SBF-cuttings technology options (see Section
III.A.4). Generally, as compared with WBF and OBFs, SBFs led to a
reduction in days required to drill a model well which leads to a
decrease in drilling costs. Additionally, EPA revised the development
drilling footage estimate due to additional information on the improved
directional drilling capabilities of SBF over WBF.
C. Economic Impacts Analyses
In response to the April 2000 NODA, EPA identified that two
projects used for economic modeling have shut in. Consequently, EPA
removed these two projects from the economic analysis. A total of 18
projects remain for the economic modeling of existing projects and 13
remain for the economic modeling of new projects.
EPA added an environmental justice (EJ) analysis which investigates
the potential for impacts on minorities and socioeconomically
disadvantaged groups under the zero discharge option. EPA performed a
Tier 1 screening analysis, which combines geographic location and U.S.
Census Bureau data to determine the number of persons living within 1
mile and 50 miles of drilling waste handling and disposal sites, their
race, and their socioeconomic status. A computer program developed by
EPA Region 6 was used to rank and characterize sites on the basis of
whether the populations near the site contain higher proportions of
minority and socioeconomically disadvantaged persons than the state as
a whole. Based on scores derived for the 13 GOM onshore drilling waste
handling and disposal sites, EPA identified five facilities that could
be potentially associated with disproportionate impacts on minorities
or socioeconomically disadvantaged groups. EPA presents the results of
the EJ analysis in Section IX.
D. Water Quality Impact and Human Health Analyses
EPA received comments regarding the heavy metal leach factors used
in the water quality impact analyses but did not receive any specific
data that could be used in the analyses (Docket No. W-98-26, Record No.
IV.A.a.2). EPA
[[Page 6861]]
therefore did not change these factors. However, EPA reevaluated the
modeling used in the proposal that metals for which there were no
factors found in the literature were completely insoluble in the
receiving water (i.e., the leach factor would be zero). EPA estimated
that these heavy metals would not be less soluble than iron which has
the lowest leach percentage factor. Thus, the iron leach factor was
transferred to the following metals for which a zero leach factor was
previously used: aluminum, antimony, beryllium, selenium, silver,
thallium, tin, and titanium.
E. Non-Water Quality Environmental Impact Analyses
As mentioned in Section III.E, EPA received additional information
regarding waste disposal practices in each of the three geographic
areas (e.g., GOM, Offshore California, Cook Inlet, Alaska). As a result
of this information, EPA revised the modeling for the fraction of waste
either injected at the drill site, injected on-shore or land disposed
(see SBF Development Document). Though the percentage of waste injected
onsite versus hauled to shore (20% vs. 80%) in the GOM remains
unchanged, the method of onshore disposal has been revised for the
final rule. In the GOM, 80% of the waste hauled to shore is injected
onshore and only 20% is landfarmed.
EPA estimates that all SBF wastes from Californian deep water
exploratory wells are sent onshore (i.e., 100% onshore disposal vs. 0%
on-site injection). For all other wells (i.e., shallow water
development and exploratory and deep water development), EPA estimates
that most of the offshore waste is disposed through offshore on-site
cuttings re-injection (i.e., 20% onshore disposal vs. 80% on-site
injection) based on the fact that most of these wells are being drilled
from fixed facilities. EPA estimates that most California offshore
wastes sent onshore are disposed via onshore formation injection (i.e.,
20% of offshore wastes sent onshore disposed via landfarming vs. 80% of
offshore wastes sent onshore disposed via onshore injection) based on
the number of California land disposal operations.
At proposal, based on the record for the 1996 Coastal rule, EPA
determined that onsite injection was not feasible throughout Cook
Inlet, Alaska (see Coastal Development Document, EPA-821-R-96-023,
Section 5.10.3). More recently, however, EPA identified in the April
2000 NODA (65 FR 21558) that the SBF rule record now demonstrates that
many Cook Inlet operators in Coastal waters are using cuttings re-
injection (see Docket No. W-98-26: Record No. III.B.a.11, Record No.
III.B.a.23, Record No. III.B.a.53). EPA contacted Cook Inlet operators
(e.g., Phillips, Unocal, Marathon Oil) and the State regulatory agency,
Alaska Oil and Gas Conservation Commission (AOGCC), for more
information on the most recent re-injection practices of Coastal and
Offshore Cook Inlet operators (65 FR 21558). AOGCC regulations provide
Cook Inlet operators the opportunity to permit and operate Class II
disposal wells and annular disposal activities. Information provided to
EPA indicate that Cook Inlet operators in Coastal waters are availing
themselves of on-site cuttings injection and are receiving AOGCC
permits for this activity. Generally, Cook Inlet operators in Coastal
waters agree that on-site injection is available for most operations.
AOGCC also agreed that there should be enough formation re-
injection disposal capacity for the small number of wells ( 5-10 wells
per year) being drilled in Cook Inlet Coastal waters. AOGCC stated,
however, that case-specific limitations should be considered when
evaluating disposal options. For instance, Unocal has experienced
difficulty establishing formation injection in several wells that were
initially considered for annular disposal. In addition, Cook Inlet
operators have the burden of proving to AOGCC's satisfaction that the
waste will be confined to the formation disposal interval. Approval of
annular disposal includes a review of cementing and leak-off test
records. In some instances the operator may also have to run a cement
bond log. When an older well is converted for use as a disposal well,
some of this information may not exist. In cases where there is
insufficient information, disposal is not allowed. Annular disposal is
also limited to the facility on which the waste is generated. Although
Class II disposal regulations don't restrict waste transport, it has
generally been the practice of the various fields' owners not to accept
any waste generated by other operators. In addition, AOGCC stated that
a zero discharge requirement poses serious technical hurdles with
respect to the handling of drilling waste for exploration drilling with
mobile rigs. Normally, there is neither capacity for storage or room
for processing equipment on exploratory drilling rigs. Therefore, to be
conservative for the NWQI analysis, EPA estimates that all of the
cuttings from the Coastal Cook Inlet operations (i.e., shallow water
wells) are re-injected (i.e., 0% onshore disposal vs. 100% on-site
injection) based on the ability of industry to dispose of oil-based
cuttings via on-site formation injection after gaining State regulatory
approval.
In order to assess the SBF NWQIs relative to the total impacts from
drilling operations, EPA included estimates of the daily drilling rig
impacts to the NWQIs from SBF-related activities. The additional
impacts consist of fuel use and air emissions resulting from the
various drilling rig pumps and motors as well as impacts of a daily
helicopter trip for transporting personnel and/or supplies. Impacts
were assessed for the number of days that an SBF interval is drilled
versus the number of days well intervals are drilled using WBFs and
OBFs and for the number of wells drilled using each of the drilling
fluids.
F. Numerical Limits for Retention of SBF Base Fluid on SBF-Cuttings
A series of potential numerical limits for retention of SBF base
fluid on SBF-cuttings were developed based in part on combinations of
data selection criteria suggested in comments on the April 2000 NODA.
These data selection criteria include: (1) Existing record of retention
calculations (i.e., ``back-up'' retort sheet information for quality
assurance/quality control purposes); and (2) foreign or domestic
location of well drilling activity (e.g., North Sea, Canada). Numerical
limits promulgated in today's final rule were based on data with
existing records of retention calculations, and they included data from
well drilling activities in foreign countries. The inclusion of data
from foreign countries is intended to include data representing
drilling with cuttings dryers at a wider range of geological formations
than just the ones for which data was received from current operations.
V. Development and Selection of Effluent Limitations Guidelines and
Standards
A. Waste Generation and Characterization
Drill cuttings are produced continuously at the bottom of the hole
at a rate dependent on a variety of factors including: (1) The
advancement of the drill bit; (2) the size and design of drill bit used
(e.g., polycrystalline diamond compact (PDC)); and (3) the drilling
fluid type used. Drill cuttings are carried to the surface by the
drilling fluid, where the cuttings are separated from the drilling
fluid by the solids control system. The drilling fluid is then
[[Page 6862]]
sent back to the active mud system (e.g., mud pumps, down hole, trip
tanks, etc.), provided it still has characteristics to meet technical
requirements. Drilling fluids cool and lubricate the drill bit,
stabilize the walls of the borehole, transport cuttings, and maintain
equilibrium between the borehole and the formation pressures. Various
sizes of drill cuttings are separated by the solids separations
equipment, and it is necessary to remove the fines (i.e., small sized
cuttings or ``low gravity solids'') as well as the large cuttings from
the drilling fluid to maintain the required rheological properties.
Increased recovery from the cuttings is more problematic for WBF
than for SBF because the WBF water-wets the cuttings which encourages
the cuttings to disperse and spoil the drilling fluid properties.
Therefore, compared to WBF, more aggressive methods of recovering SBF
from the cuttings wastestream are practical.
SBFs, used or unused, are a valuable commodity and not a waste. It
is industry practice to continuously reuse the SBF while drilling a
well interval, and at the end of the well, to ship the remaining SBF
back to shore for refurbishment and reuse. One of the main incentives
for operators to attempt to recover as much SBF as possible during
drilling is the relatively high unit cost of SBF, approximately $160 to
$300 per barrel, as compared to OBFs ($70 to 90 per barrel) and WBFs
($45 per barrel) (Docket No. W-98-26, Record No. IV.B.a.13). Operators
involved in the first 1998 GOM field demonstrations of cuttings dryers
(i.e., advanced solids control technology) were attempting to obtain
further reductions in drilling costs, beyond that obtained by
shortening the overall drilling time for the well, by recovering more
SBF. SBFs are relatively easy to separate from the drill cuttings
because the drill cuttings do not disperse or hydrate in the drilling
fluid to the same extent as compared to WBFs. Reducing cuttings
hydration is particularly important in certain formations (e.g., shale
formations in GOM). With WBF, due to dispersion of the drill cuttings,
drilling fluid components often need to be added to maintain the
required drilling fluid properties. These additions are often in excess
of what the drilling system can accommodate. The excess ``dilution
volume'' of WBF is a resultant waste. This dilution volume waste does
not occur with SBF. For these reasons, SBF is only discharged as a
contaminant of the drill cuttings wastestream. It is not discharged on
purpose as neat drilling fluid (i.e., drilling fluid not associated
with cuttings).
Current practice is that the top well section is normally drilled
with a WBF. As the well becomes deeper, the performance requirements of
the drilling fluid increase, and the operator may, at some point,
decide that the drilling fluid system should be changed to either a
traditional OBF, based on diesel oil or mineral oil, or an SBF. The
system, including the drill string and the solids separation equipment,
must be changed entirely from the WBF to the SBF (or OBF) system, and
the two do not function as a blended system. The entire system is
either: (1) A water dispersible (aqueous) drilling fluid such as a WBF;
or (2) an oleaginous drilling fluid such as OBFs, enhanced mineral oil
based drilling fluids, or SBFs. The decision to change the system from
a WBF water dispersible system to an oleaginous drilling fluid depends
on many factors including:
I. The operational considerations (e.g., rig type, risk of riser
disconnects, rig equipment, and distance from support facilities);
II. The relative drilling performance of one type fluid compared to
another (e.g., rate of penetration, well angle, hole size/casing
program options, compatible drilling bit, and horizontal deviation);
III. The presence of geologic conditions that favor a particular
fluid type or performance characteristic (e.g., formation stability/
sensitivity, formation pore pressure vs. fracture gradient, and
potential for gas hydrate formation);
IV. Drilling fluid cost (i.e., base cost plus daily operating
cost);
V. drilling operation cost (i.e., rig cost plus logistic and
operation support); and
VI. Drilling waste disposal cost.
Industry has commented that while the right combination of factors
that favor the use of SBF can occur in any area, they most frequently
occur with ``deep water'' operations (i.e., greater than or equal to
1,000 feet of water). This is due to the fact that these operations are
higher cost and can therefore better justify the higher initial cost of
SBF use. Industry has also commented that SBF may be increasingly used
in shallow water wells due to the ability of SBF to increase average
rates of penetration and shorten average times to complete drilling
operations (Docket No. W-98-26, Record No. IV.A.a.3).
The volume of cuttings generated while drilling the SBF or OBF
intervals of a well depends on the type of well (development or
production) and the water depth (shallow or deep). EPA developed OBF
and SBF model well characteristics from information provided by the
American Petroleum Institute (API). API provided well size date for
four types of wells currently drilling the GOM: development and
exploratory wells in both deep water (i.e., greater than or equal to
1,000 feet of water) and shallow water (i.e., less than 1,000 feet of
water). These model wells are referred to as: (1) Shallow-water
development (SWD); (2) shallow-water exploratory (SWE); (3) deep-water
development (DWD); and (4) deep-water exploratory (DWE). For the four
model wells, EPA determined that the volumes of cuttings generated by
these SBF or OBF well intervals are (in barrels): 565 for SWD; 1,184
for SWE; 855 for DWD; and 1,901 for DWE. These volumes represent only
the rock, sand, and other formation solids drilled from the hole, and
do not include drilling fluid that adheres to these formation cuttings.
These values also include the additional formation cuttings volume of
7.5% washout. Washout is caving in or sloughing off of the well bore.
Washout, therefore, increases hole volume and increases the amount of
cuttings generated when drilling a well. The washout percentage EPA
used in its analyses (i.e., 7.5%) is based on the rule of thumb
reported by industry representatives of 5 to 10% washout when drilling
with SBF or OBF.
Drilling fluid returning from the well is laden with drill
cuttings. The drill cuttings range in size from large particles which
are on the order of a centimeter or more in size to small particles
(i.e., fines or ``low gravity solids'') which are fractions of a
millimeter in size. Standard or current practice solids control systems
employ primary and secondary shale shakers in series with a ``fines
removal unit'' (e.g., decanting centrifuge or mud cleaner). The
drilling fluid and drill cuttings from the well are first passed
through primary shale shakers. These shakers remove the largest
cuttings which are approximately 1 to 5 millimeters in size. The
drilling fluid recovered from the primary shakers is then passed over
secondary shale shakers to remove smaller drill cuttings. Finally, a
portion or all of the drilling fluid recovered from the primary and
secondary shakers may be passed through the fines removal unit to
remove fines from the drilling fluid. It is important to remove fines
from the drilling fluid in order to maintain the desired rheological
properties of the active drilling fluid system (e.g., viscosity,
density). Thus, the cuttings wastestream normally consists of
discharged cuttings from the primary and secondary shale shakers and
fines from the fines removal unit.
[[Page 6863]]
Operators using improved solids control technology process the
cuttings discarded from the primary and secondary shale shakers through
a ``cuttings dryer'' (e.g., vertical or horizontal centrifuge, squeeze
press mud recovery unit, High-G linear shaker). The cuttings from the
cuttings dryer are discharged and the recovered SBF is sent to the
fines removal unit. The advantage of the cuttings dryer is that more
SBF is recovered for re-use and less SBF is discharged into the ocean.
This, consequently, will reduce the pollutant loadings to the ocean and
the potential of the waste to cause anoxia (lack of oxygen) in the
receiving sediment.
As discussed in the April 2000 NODA (65 FR 21569), solids control
equipment generally breaks larger particles into smaller particles. An
undesirable increase in drilling fluid weight and viscosity can occur
when drill solids degrade into fines and ultra-fines. Ultra-fines are
generally classified as being less than 5 microns (10-6
meters) in length and solids control equipment generally cannot remove
these ultra-fines. An unacceptable high fines content (i.e., generally
> 5% of total drilling fluid weight) may consequently lead to drilling
problems (e.g., undesirable rheological properties, stuck pipe).
Therefore, it is possible that the increased recovery of SBF from
cuttings for re-use in the active mud system, often achieved through
use of the cuttings dryer in solids control systems, may lead to a
build-up in fines for certain formation characteristics (e.g., high
reactivity of formation cuttings, limited loss of drilling fluid into
the formation). In the April 2000 NODA, EPA solicited comments
regarding whether EPA's proposed numeric cuttings retention value might
cause operators (where there are unfavorable formation characteristics)
to: (1) Dilute the fines in the active mud system through the addition
of ``fresh'' SBF; and/or (2) capture a portion of the fines in a
container and send the fines to shore for disposal.
Comments from API/NOIA identified only one instance in which the
use of a cuttings dryer in combination with a fines removal unit in the
United States may have lead to an increase in ``fines build-up'' and a
loss of circulation event (Docket No. W-98-26, Record No. IV.A.a.13).
Further communication with additional industry stakeholders identified
that this well (Shell, Green Canyon 69, OCS-G-13159#3) was the first
application of the cuttings dryer type (horizontal centrifuge cuttings
dryer) in the GOM and inexperience with this type of technology may
have contributed to the build-up of fines causing well problems.
However, other commentors stated that fines build-up was not an issue
for the well in question (Docket No. W-98-26, Record No. IV.A.b.1).
Moreover, further industry comments revealed that the properties of
formations are often the main culprit of loss circulation and that the
same rig (Marianas) had a loss of circulation at another nearby well in
the same formation when a cuttings dryer was not being used (Docket No.
W-98-26, Record No. IV.A.b.1). Therefore, based on the record, which
includes over three dozen successful cuttings dryer deployments, EPA
concludes that fines build up is not an issue of concern when operators
properly operate and maintain cuttings dryers and fines removal
equipment.
Drill cuttings are typically discharged continuously as they are
separated from the drilling fluid in the solids separation equipment.
The drill cuttings will also carry a residual amount of adhered
drilling fluid. Therefore, the two parameters that make up the bulk of
the pollutant loadings are TSS and what is measured by the API Retort
Method (Appendix 7) as Total Oil. TSS is comprised of two components:
the drill cuttings themselves and the solids in the adhered drilling
fluid. The drill cuttings are primarily small bits of stone, clay,
shale, and sand. The source of the solids in the drilling fluid is
primarily the barite weighting agent, and clays (e.g., amine clays)
which are added for filtration control and to modify the rheological
properties. Benthic smothering and/or sediment grain size alteration
resulting in potential damage to invertebrate populations and
alterations in benthic community structure is a concern with
uncontrolled SBF drilling discharges due to the quantity and
characteristics of associated TSS discharges. In general, large
cuttings particles with a high percentage of adhering SBF (e.g., >12%
(wt. SBF)/(wt. wet cuttings)) tend to conglomerate and quickly settle
out to the benthic environment quickly near the well site.
Additionally, environmental impacts can be caused by toxic,
conventional, and non-conventional pollutants adhering to the solids.
The adhered SBF drilling fluid is mainly composed, on a volumetric
basis, of the synthetic material (i.e., ``base fluid''). Formation oil
can also contaminate SBF-cuttings and contribute priority,
conventional, and non-conventional pollutants. The oleaginous material
(i.e., SBF base fluid and formation oil) may be toxic and it may
contain priority pollutants such as polynuclear aromatic hydrocarbons
(PAHs). Depending on bottom currents, temperature, and rate of
biodegradation this oleaginous material may cause hypoxia (i.e.,
reduction in dissolved oxygen concentrations) or anoxia (i.e., absence
of dissolved oxygen) in the immediate sediment. Oleaginous materials
which biodegrade quickly will reduce dissolved oxygen concentrations
more rapidly than more slowly degrading oleaginous materials. EPA,
however, thinks that fast biodegradation is environmentally preferable
to slower biodegradation despite the increased risk of temporary
hypoxia which accompanies fast biodegradation. EPA's position is
supported by published seabed surveys which show that benthic re-
colonization by infaunal individuals after the discharge of SBF-
cuttings or OBF-cuttings can be correlated with the disappearance of
the base fluid in the sediment. Large persistent cuttings piles may
provide a source of environmental contamination for many years (Docket
No. W-98-26, Record No. IV.F.2). Moreover, benthic re-colonization
rates do not seem to be correlated with the severity of any hypoxic or
anoxic effects that may result while the SBF base fluid is degrading or
dispersing. Numerous studies show that SBF base fluids that biodegrade
faster lead to a more rapid recovery of the pre-discharge benthic
community.
As a component of the drilling fluid, the barite weighting agent is
also discharged as a contaminant of the drill cuttings. Barite is a
mineral principally composed of barium sulfate (BaSO4), and
it is known to generally have trace contaminants of several toxic heavy
metals such as mercury, cadmium, arsenic, chromium, copper, lead,
nickel, and zinc. SBF also contain non-conventional pollutants found in
other drilling fluid components (e.g., emulsifiers, oil wetting agents,
filtration control agents, and viscosifiers).
As previously stated in the April 2000 NODA (65 FR 21560), EPA
learned that SBF is controlled with zero discharge practices at the
drill floor, in the form of vacuums and sumps to retrieve spilled
fluid. EPA also learned that approximately 75 barrels of fine solids
and barite, which have an approximate SBF content of 25%, can
accumulate in the dead spaces of the mud pit, sand trap, and other
equipment in the drilling fluid circulation system. Current practice is
to either wash these solids out with water for overboard discharge, or
to retain the waste solids for disposal. Several hundred barrels
(approximately 200 to 400 barrels) of water are used to wash out the
mud pits. Industry representatives also indicated to EPA that those oil
and gas extraction
[[Page 6864]]
operations that discharge wash water and accumulated solids first
recover free SBF.
B. Selection of Pollutant Parameters
1. Stock Limitations and Standards for Base Fluids
a. General. In the final rule, where SBF-cuttings may be
discharged, except for Cook Inlet, Alaska, EPA is establishing BAT
limitations and NSPS that require the synthetic materials which form
the base fluid of the SBFs to meet limitations and standards on PAH
content, sediment toxicity, and biodegradation. If these stock
limitations are not met the technology basis for meeting these
limitations and standards is: (1) Product substitution; or (2) zero
discharge based on land disposal or cuttings re-injection. The
regulated toxic, conventional, and non-conventional pollutant
parameters are identified below. A large range of synthetic,
oleaginous, and water miscible materials are available for use as base
fluids. These stock limitations on the base fluid are intended to
encourage product substitution reflecting best available technology and
best available demonstrated technology wherein only those synthetic
materials and other base fluids which minimize potential loadings and
toxicity may be discharged. Additionally, EPA is retaining BPT and BCT
requirements for SBFs and SBF-cuttings as no discharge of free oil as
determined by the static sheen text (Appendix 1 of subpart A of 40 CFR
Part 435).
As stated below in Section V.F, EPA is today promulgating BPT, BCT,
BAT, and NSPS for SBFs and SBF-cuttings for Coastal Cook Inlet, Alaska
as zero discharge except when Coastal Cook Inlet, Alaska, operators are
unable to dispose of their SBF-cuttings using any of the following
disposal options: (1) On-site re-injection (annular disposal or Class
II UIC); (2) re-injection using a nearby Coastal or Offshore Class II
UIC disposal well; or (3) onshore disposal using a nearby Class II UIC
disposal well or land application. If an operator is able to make these
showings, then the operator would be subject to the same requirements
for SBF-cuttings that apply elsewhere. The regulated toxic,
conventional, and non-conventional pollutant parameters are identified
below.
b. PAH Content. EPA is regulating the PAH content of base fluids
because PAHs are comprised of toxic priority pollutants. SBF base
fluids typically do not contain PAHs, whereas the traditional OBF base
fluids of diesel and mineral oil typically contain 5 to 10% PAH and
0.35% PAH respectively. The PAHs typically found in diesel and mineral
oil include: (1) the toxic priority pollutants fluorene, naphthalene,
phenanthrene, and others; and (2) non-conventional pollutants such as
alkylated benzenes and biphenyls. Therefore, the PAH BAT limitation and
NSPS are components of this final regulation to help discriminate
between acceptable and non-acceptable base fluids.
c. Sediment Toxicity. EPA is also regulating the sediment toxicity
in base fluids as a non-conventional pollutant parameter and as an
indicator for toxic pollutants and non-conventional pollutants in base
fluids (e.g., enhanced mineral oils, internal olefins, linear alpha
olefins, poly alpha olefins, paraffinic oils, C12-
C14 vegetable esters of 2-hexanol and palm kernel oil, ``low
viscosity'' C8 esters, and other oleaginous materials). It
has been shown, during EPA's development of the Offshore Guidelines,
that establishing limits on toxicity encourages the use of less toxic
drilling fluids and additives. Many of the SBF base fluids have been
shown to have lower toxicity than OBF base fluids, but among SBFs some
are more toxic than others. Today's final discharge option (i.e., BAT/
NSPS Option 2) includes a base fluid sediment toxicity stock
limitation, as measured by the 10-day sediment toxicity test (ASTM
E1367-92) using a natural sediment or formulated sediment and
Leptocheirus plumulosus as the test organism.
d. Biodegradation. EPA is also regulating the biodegradation in
base fluids as an indicator of the extent, in level and duration, of
the toxic effect of toxic pollutants and non-conventional pollutants
present in the base fluids (e.g., enhanced mineral oils, internal
olefins, linear alpha olefins, poly alpha olefins, paraffinic oils,
C12-C14 vegetable esters of 2-hexanol and palm
kernel oil, ``low viscosity'' C8 esters, and other
oleaginous materials). Based on results from seabed surveys at sites
where various base fluids have been discharged with drill cuttings, EPA
believes that the results from the three biodegradation tests used
during the rulemaking (i.e., solid phase test, anaerobic closed bottle
biodegradation test, respirometry biodegradation test) are indicative
of the relative rates of biodegradation in the marine environment. In
addition, EPA thinks the biodegradation parameter correlates strongly
with the rate of recovery of the seabed where OBF- and SBF-cuttings
have been discharged. The various base fluids vary widely in
biodegradation rates, as measured by the three biodegradation methods.
However, the relative ranking of the base fluids remain relatively
similar across all three biodegradation tests.
As originally proposed in February 1999 (64 FR 5504) and re-stated
in the April 2000 NODA (65 FR 21550), EPA is today promulgating a BAT
limitation and NSPS to control the minimum amount of biodegradation of
base fluid. Today's final discharge option (i.e., BAT/NSPS Option 2)
includes a base fluid biodegradation stock limitation, as measured by
the marine anaerobic closed bottle biodegradation test (i.e., ISO
11734).
e. Bioaccumulation. EPA also considered establishing a BAT
limitation and NSPS that would limit the base fluid bioaccumulation
potential. The regulated parameters would be the non-conventional and
toxic priority pollutants that bioaccumulate. EPA reviewed the current
literature to identify the bioaccumulation potential of various base
fluids. EPA determined that SBFs are not expected to significantly
bioaccumulate because of their extremely low water solubility and
consequent low bioavailability. Their propensity to biodegrade makes
them further unlikely to significantly bioaccumulate in marine
organisms.
EPA identified that hydrophobic chemicals (e.g., ester base fluids)
that have a log Kow less than about 3 to 3.5 may
bioaccumulate rapidly but not to high concentrations in tissues of
marine organisms, particularly if they are readily biodegradable into
non-toxic metabolites (Docket No. W-98-26, Record No. IV.F.1). (Note:
The octanol/water partition coefficient (Kow) is used as a
surrogate for estimating lipid/water partitioning). Moreover,
hydrophobic chemicals (e.g., C16-C18 internal
olefins, various poly alpha olefins, and C18 n-paraffins)
with a log Kow greater than about 6.5 to 7 do not
bioaccumulate effectively from the water, because their solubility in
both the water and lipid phases is very low (Docket No. W-98-26, Record
No. IV.F.1). Finally, the degradation by-products of SBF base fluids
(e.g., alcohols) are likely to be more polar (i.e., more miscible with
water) than the parent substances. The higher water solubility will
result in these degradation by-products partitioning into the water
column and being diluted to toxicologically insignificant
concentrations.
2. Discharge Limitations
a. Free Oil. Under BPT and BCT limitations for SBF-cuttings, EPA
retains the prohibition on the discharge of free oil as determined by
the static sheen test
[[Page 6865]]
(see Appendix 1 of subpart A of 40 CFR part 435). Under this
prohibition, drill cuttings may not be discharged when the associated
drilling fluid would fail the static sheen test. The prohibition on the
discharge of free oil is intended to minimize the formation of sheens
on the surface of the receiving water. The regulated parameter of the
no free oil limitation would be the conventional pollutant oil and
grease which separates from the SBF and causes a sheen on the surface
of the receiving water.
The free oil discharge prohibition does not control the discharge
of oil and grease and crude oil contamination in SBFs as it would in
WBFs. With WBFs, oils which may be present (e.g., diesel oil, mineral
oil, formation oil, or other oleaginous materials) are present as the
discontinuous phase. As such these oils are free to rise to the surface
of the receiving water where they may appear as a film or sheen upon or
discoloration of the surface. By contrast, the oleaginous matrices of
SBFs do not disperse in water. In addition they are weighted with
barite, which causes them to sink as a mass without releasing either
the oleaginous materials which comprise the SBF or any contaminant
formation oil. Thus, the test would not identify these pollutants.
However, a portion of the SBF may rise to the surface to cause a sheen.
The components that rise to the surface fall under the general category
of oil and grease and are considered conventional pollutants.
Therefore, the purpose of the no free oil limitation of today's final
regulation is to control the discharge of conventional pollutants which
separate from the SBF and cause a sheen on the surface of the receiving
water. The limitation is not intended to control formation oil
contamination nor the total quantity of conventional pollutants
discharged.
b. Formation Oil Contamination. As originally proposed in February
1999 (64 FR 5505) and re-stated in the April 2000 NODA (65 FR 21552),
EPA is today promulgating a BAT limitation and NSPS of zero discharge
to control formation oil contamination on SBF-cuttings. EPA is also
today promulgating a screening method (Reverse Phase Extraction (RPE)
method presented in Appendix 6 to subpart A of part 435) and a
compliance assurance method (Gas Chromatograph/Mass Spectrometer (GC/
MS) method presented in Appendix 5 to subpart A of part 435).
Formation oil is an ``indicator'' pollutant for the many toxic and
priority pollutant pollutants present in formation (crude) oil (e.g.,
aromatic and polynuclear aromatic hydrocarbons). These pollutants
include benzene, toluene, ethylbenzene, naphthalene, phenanthrene, and
phenol. EPA is requiring that formation oil contamination be measured
at two points. First, EPA is requiring that operators verify and
document that a SBF is free of formation oil contamination before
initial use of the SBF through use of the GC/MS compliance assurance
method (Appendix 5 to subpart A of 40 CFR part 435). Second, EPA is
requiring that operators use the RPE method (Appendix 6 to subpart A of
40 CFR part 435) for the SBF recovered by the solids control equipment
to detect formation oil contamination. The RPE method is a fluorescence
test and is appropriately ``weighted'' to better detect crude oils.
These crude oils contain more toxic aromatic and PAH pollutants and
show brighter fluorescence (i.e., noncompliance) in the RPE method at
lower levels of crude oil contamination. Since the RPE method is a
relative brightness test, operators may also use the GC/MS compliance
assurance method when the results from the RPE method are in doubt by
either the operator or the enforcement authority. Results from the GC/
MS compliance assurance method will supersede those of the RPE method.
c. Retention of Drilling Fluid on Cuttings. EPA is today
promulgating a BAT limitation and NSPS to control the retention of
drilling fluid on drill cuttings. The BAT limitation and NSPS are
presented as the percentage of base fluid on wet cuttings (i.e., mass
base fluid (g)/mass wet cuttings (g)), averaged over the entire well
sections drilled with SBF. The limitation and standard controls the
quantity of drilling fluid discharged with the drill cuttings. Both
toxic pollutants and non-conventional pollutants would be controlled by
this limitation. Several pollutants are present in the barite weighting
agent, including the toxic metal pollutants arsenic, chromium, copper,
lead, mercury, nickel, and zinc, and the non-conventional metal
pollutants aluminum and tin. A complete SBF formulation also includes
non-conventional pollutants found in the SBF base fluids (e.g.,
enhanced mineral oils, internal olefins, linear alpha olefins, poly
alpha olefins, paraffinic oils, C12-C14 vegetable
esters of 2-hexanol and palm kernel oil, ``low viscosity''
C8 esters, and other oleaginous materials) and in other
drilling fluid components (e.g., emulsifiers, oil wetting agents,
filtration control agents, and viscosifiers). These pollutants would
not be controlled by the sediment toxicity stock limitations. In
response to the February 1999 proposal (64 FR 5501), EPA received
comments that these non-conventional pollutants include fatty acids
(Docket No. W-98-26, Record No. III.A.a.7). EPA also received further
information that the non-conventional pollutants in these drilling
fluid components include amine clays, amine lignites, and dimer/trimer
fatty acids (Docket No. W-98-26, Record No. III.B.b.1).
This limitation would also control the toxic effect of the drilling
fluid and the persistence or biodegradation of the base fluid.
Specifically, as stated in the April 2000 NODA (65 FR 21553), lowering
the percentage of residual drilling fluid retained on cuttings
increases the recovery rate of the seabed receiving the cuttings
(Docket No. W-98-26, Record No. I.D.b.30 and 31; Record No.
III.B.a.15). Limiting the amount of SBF content in discharged cuttings
controls: (1) The amount of toxic and non-conventional pollutants in
SBF which are discharged to the ocean; (2) the biodegradation rate of
discharged SBF; and (3) the potential for SBF-cuttings to develop
cuttings piles and mats which are deleterious to the benthic
environment.
As originally proposed in February 1999 (64 FR 5547) and re-stated
in the April 2000 NODA (65 FR 21552), EPA is today promulgating a
retort and sampling compliance method for the cuttings retention BAT
limitation and NSPS (see Appendix 7 to subpart A of 40 CFR part 435;
API Recommended Practice 13B-2).
d. Sediment Toxicity. EPA is also regulating the sediment toxicity
in SBF discharged with cuttings as a non-conventional pollutant
parameter and as an indicator for toxic pollutants in SBFs. As
originally proposed in February 1999 (64 FR 5491) and re-stated in
April 2000 (65 FR 21557), EPA is today promulgating a BAT limitation
and NSPS to control the maximum sediment toxicity of the SBF discharged
with cuttings at the point of discharge. The sediment toxicity of the
SBF-cuttings at the point of discharge is measured by the modified
sediment toxicity test (ASTM E1367-92) using a natural sediment or
formulated sediment and Leptocheirus plumulosus as the test organism.
EPA finds that the sediment toxicity test at the point of discharge
is practical as an indicator of the sediment toxicity of the drilling
fluid at the point of discharge. The sediment toxicity test applied at
the point of discharge will control non-conventional pollutants found
in some drilling fluid components (e.g., emulsifiers, oil wetting
agents, filtration control agents,
[[Page 6866]]
and viscosifiers) which are added to the base fluid in order to build a
complete SBF package. Other possible toxic pollutants in drilling
fluids may include mercury, cadmium, arsenic, chromium, copper, lead,
nickel, and zinc, and formation oil contaminants. As previously stated,
establishing discharge limits on toxicity encourages the use of less
toxic drilling fluids and additives. The modifications to the 10-day
sediment toxicity test include shortening the test to 96-hours.
Shortening the test will allow operators to continue drilling
operations while the sediment toxicity test is being conducted on the
discharged drilling fluid. Moreover, discriminatory power is
substantially reduced for the 10-day test on drilling fluid as compared
to the 96-hour test (i.e., the 10-day test is of lower practical use in
determining whether a SBF is substantially different from OBFs).
Finally, operators discharging WBFs are already complying with a
biological test at the point of discharge, the 96-hour SPP toxicity
test, which tests whole WBF aquatic toxicity using the test organism
Mysidopsis bahia.
3. Maintenance of Current Requirements
Today's rule does not modify the existing BAT and NSPS limitations
on the stock barite of 1 mg/kg mercury and 3 mg/kg cadmium. These
limitations 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 Section VI, Offshore Development Document,
EPA-821-R-93-003).
Today's rule does not modify the existing BAT and NSPS limitations
prohibiting the discharge of drilling wastes containing diesel oil in
any amount. Diesel oil is considered an ``indicator'' for the control
of specific toxic pollutants. These pollutants include benzene,
toluene, ethylbenzene, naphthalene, phenanthrene, and phenol. Diesel
oil may contain from 3 to 10% by volume PAHs, which constitute the more
toxic pollutants in petroleum products.
Today's rule does not modify the existing BAT limitation and NSPS
for controlling the maximum aqueous phase toxicity of SBF-cuttings at
point of discharge using the suspended particulate phase (SPP) test
(see Appendix 2 of subpart A of Part 435). The BAT limitation and NSPS
for controlling aqueous toxicity of discharged SBF-cuttings is retained
as the minimum 96-hour LC50 of the SPP shall be 3% by
volume. EPA is interested in controlling the toxicity of drilling
fluids in the sediment and the water column and is requiring both a
sediment toxicity test and an aqueous phase toxicity test to assess
overall toxicity of the drilling fluid at the point of discharge. EPA
finds that the SPP test at the point of discharge is practical as a
measurement of the aquatic toxicity of the drilling fluid at the point
of discharge. The discharge SPP test will control non-conventional
pollutants found in drilling fluid components (e.g., emulsifiers, oil
wetting agents, filtration control agents, and viscosifiers) which are
added to the base fluid in order to build a complete SBF package.
Moreover, operators discharging WBFs are already complying with the SPP
toxicity test on discharged WBFs.
C. Regulatory Options Considered and Selected for Drilling Fluid Not
Associated With Drill Cuttings
In the February 1999 proposal, EPA proposed BPT, BCT, BAT, and NSPS
as zero discharge for SBFs not associated with drill cuttings. In the
April 2000 NODA, EPA published two options for the final rule for the
BAT limitation and NSPS for controlling SBFs not associated with SBF
drill cuttings: (1) Zero discharge; or (2) allowing operators to choose
either zero discharge or an alternative set of BMPs with an
accompanying compliance method. Industry supported the second option
stating that the first option (zero discharge) would result in the
costly and potentially dangerous collection, shipping, and disposal of
large quantities of rig site wash water containing only a small
quantity of SBF (Docket No. W-98-26, Record No. IV.A.a.13). Industry
also stated that BMPs would be extremely effective at reducing the
quantity of non-cuttings related SBF and would focus operators'
attention on reducing these discharges.
EPA is today promulgating BPT, BCT, BAT, and NSPS of zero discharge
for SBFs not associated with drill cuttings. This wastestream consists
of neat SBFs that are intended for use in the downhole drilling
operations (e.g., drill bit lubrication and cooling, hole stability).
This wastestream is transferred from supply boats to the drilling rig
and can be released during these transfer operations. This wastestream
is often spilled on the drill deck but contained through grated
troughs, vacuums, or squeegee systems. This wastestream is also held in
numerous tanks during all phases of the drilling operation (e.g., trip
tanks, storage tanks). EPA received information that rare occurrences
of improper SBF transfer procedures (e.g., no bunkering procedures in
place for rig loading manifolds) and improper operation of active mud
system equipment (e.g., no lock-out, tag-out procedures in place for
mud pit dump valves) has the potential for the discharge of tens to
hundreds of barrels of neat SBF, or SBF not associated with cuttings,
if containment is not practiced (Docket No. W-98-26, Record No.
IV.A.a.26, QTECH LTD Reports for Ocean America and Discoverer 534).
Current practice for control of SBF not associated with drill
cuttings is zero discharge (e.g., drill deck containment, bunkering
procedures), primarily due to the value of SBFs recovered and reused.
Therefore, zero discharge for SBF not associated with drill cuttings is
technologically available and economically achievable. Moreover, these
controls generally allow the re-use of SBF in the drilling operation
and has no unacceptable NWQIs.
EPA has also decided that solids accumulated at the end of the well
(``accumulated solids'') and wash water used to clean out accumulated
solids or on the drill floor are associated with drill cuttings and are
therefore not controlled by the zero discharge requirement for SBFs not
associated with drill cuttings (see Section V.F.2.b).
D. BPT Technology Options Considered and Selected for Drilling Fluid
Associated With Drill Cuttings
EPA is today promulgating BPT effluent limitations for the cuttings
contaminated with SBFs (``SBF-cuttings''). The BPT effluent limitations
promulgated today for SBF-cuttings would control free oil as a
conventional pollutant. The BPT limitation is no free oil as measured
by the static sheen test, performed on SBF separated from the cuttings
in U.S. Offshore waters and Coastal Cook Inlet, Alaska.
In setting the no free oil limitation in U.S. Offshore waters and
Coastal Cook Inlet, Alaska, EPA considered the sheen characteristics of
currently available SBFs. Since this requirement is currently met by
dischargers in the GOM, EPA anticipates no additional costs to the
industry to comply with this limitation. Therefore, EPA believes that
this limitation represents the appropriate level of control for SBFs
associated with drill cuttings.
[[Page 6867]]
E. BCT Technology Options Considered and Selected for Drilling Fluid
Associated With Drill Cuttings
In July 1986, EPA promulgated a methodology for establishing BCT
effluent limitations. EPA evaluates the reasonableness of BCT candidate
technologies--those that are technologically feasible--by applying a
two part cost test: (1) A POTW test; and (2) an industry cost-
effectiveness test.
EPA first calculates the cost per pound of conventional pollutant
removed by industrial dischargers in upgrading from BPT to a BCT
candidate technology and then compares this cost to the cost per pound
of conventional pollutants removed in upgrading POTWs from secondary
treatment. The upgrade cost to industry must be less than the POTW
benchmark of $0.25 per pound (in 1976 dollars). In the industry cost-
effectiveness test, the ratio of the incremental BPT to BCT cost
divided by the BPT cost for the industry must be less than 1.29 (i.e.,
the cost increase must be less than 29%).
The BCT effluent limitations promulgated today would control free
oil as a conventional pollutant. EPA is today promulgating a BCT
effluent limitation for SBF-cuttings of no free oil equivalent to the
BPT limitation for SBF-cuttings of no free oil as determined by the
static sheen test in U.S. Offshore waters and Coastal Cook Inlet,
Alaska.
In developing BCT limits for the U.S. Offshore waters and Coastal
Cook Inlet, Alaska, EPA considered whether there are technologies
(including drilling fluid formulations) that achieve greater removals
of conventional pollutants than promulgated for BPT, and whether those
technologies are cost-reasonable according to the BCT Cost Test. EPA
identified no technologies that can achieve greater removals of
conventional pollutants as compared with the U.S. Offshore waters and
Coastal Cook Inlet BPT requirements that are also cost-reasonable under
the BCT Cost Test. Accordingly EPA is today promulgating BCT effluent
limitations for SBF-cuttings equal to the promulgated BPT effluent
limitations for SBF-cuttings in U.S. Offshore waters and Coastal Cook
Inlet, Alaska.
F. BAT Technology Options Considered and Selected for Drilling Fluid
Associated With Drill Cuttings
EPA is promulgating stock limitations and discharge limitations in
a two part approach to control SBF-cuttings discharges under BAT. The
first part is based on product substitution through use of stock
limitations (e.g., sediment toxicity, biodegradation, PAH content,
metals content) and discharge limitations (e.g., diesel oil
prohibition, formation oil prohibition, sediment toxicity, aqueous
toxicity). The second part is the control of the quantity of SBF
discharged with SBF-cuttings. As previously stated in the April 2000
NODA, EPA finds that the second part is particularly important because
limiting the amount of SBF content in discharged cuttings controls: (1)
The amount of SBF discharged to the ocean; (2) the biodegradation rate
of discharged SBF; and (3) the potential for SBF-cuttings to develop
cuttings piles and mats which are detrimental to the benthic
environment.
EPA is also today retaining the existing BAT limitations on: (1)
The stock barite of 1 mg/kg mercury and 3 mg/kg cadmium; (2) the
maximum aqueous toxicity of discharged SBF-cuttings as the minimum 96-
hour LC50 of the Suspended Particulate Phase toxicity test
(SPP) shall be 3% by volume; and (3) prohibiting the discharge of
drilling wastes containing diesel oil in any amount. These limitations
control the levels of toxic metal and aromatic pollutants respectively.
EPA at this time thinks that all of these components are essential for
appropriate control of SBF-cuttings discharges.
The BAT effluent limitations promulgated today for SBF-cuttings
would control a variety of toxic and non-conventional pollutants in the
stock base fluids by controlling their PAH content, sediment toxicity,
and biodegradation. The BAT effluent limitations promulgated today for
SBF-cuttings would also control a variety of toxic and non-conventional
pollutants at the point of discharge by controlling formation oil
contamination, sediment toxicity, and the quantity of SBF discharged.
The BAT stock and discharge limitations are described below.
The BAT level of control in the U.S. Offshore waters has been
developed taking into consideration among other things: (1) The
availability, cost, and environmental performance of SBF base fluids in
terms of PAH content, sediment toxicity, and biodegradation rate; (2)
the availability, cost, and environmental performance of SBFs retained
on the cuttings discharge in terms of sediment toxicity and
biodegradation rate; (3) the frequency of formation oil contamination
at the various control levels for the discharges; (4) the availability,
cost, and environmental performance of equipment and methods to recover
SBF from the drill cuttings being discharged; and (5) the NWQIs of each
option. By environmental performance, EPA means both a reduction in the
quantity of pollutants discharged to the ocean and a reduction in their
environmental effects in terms of sediment toxicity, aquatic toxicity,
and biodegradation rate. Issues related to the technical availability
and economic achievability of today's promulgated BAT limitations are
discussed below by regulated parameter. The NWQIs of each selected
option is discussed in Section VIII below. EPA also considered NWQIs in
selecting the controlled discharge option for SBF-cuttings (i.e., BAT/
NSPS Option 2) (see Section VIII).
EPA and industry sediment toxicity and biodegradation laboratory
studies show that both vegetable esters and low viscosity esters have
better environmental performance than all other SBF base fluids. EPA,
however, rejected the option of basing BAT sediment toxicity and
biodegradation stock limitations and NSPS solely on vegetable esters
and low viscosity esters because the record does not indicate that
these fluids can be used in drilling situations throughout the offshore
subcategory nor could EPA predict the conditions and circumstances
where these fluids would be able to be used (see Section V.F.1.a). EPA
is sufficiently satisfied, however, that both esters provide better
environmental performance (e.g., sediment toxicity, biodegradation).
Consequently, EPA is promulgating an alternative higher retention on
cuttings (ROC) BAT discharge limitation to encourage the use of esters.
The higher ROC discharge limitation for SBFs complying with the stock
limitations based on esters is derived from data representing four
cuttings dryer technologies (e.g., vertical centrifuge, horizontal
centrifuge, squeeze press mud recovery unit, and High-G linear shaker).
The lower ROC BAT discharge limitation for the SBFs complying with the
C16-C18 internal olefin stock limitations is
based on data from the two top performing cuttings dryer technologies
(e.g., vertical centrifuge and horizontal centrifuge). EPA data
demonstrates that operators properly using these cuttings dryer
technologies (e.g., vertical centrifuge, horizontal centrifuge, squeeze
press, High-G linear shaker) will be able to comply with the final
higher ROC numerical limitation for ester-based SBFs. EPA believes that
this balancing of the importance of retention values with environmental
performance as reflected by sediment toxicity and biodegradation rates
is justified because of the greater ability of esters to
[[Page 6868]]
biodegrade and of their lower sediment toxicity.
Therefore, EPA balanced the environmental performance of the base
fluid (in terms of sediment toxicity and biodegradation) with the
environmental performance of cuttings associated with drilling fluids
(in terms of the retention on cuttings limit) to determine the
appropriate best available technology. EPA determined that the improved
toxicity and biodegradation of the ester based fluids justified
increased flexibility in the ROC limitation as long as the limitation
reflected the use of cuttings dryers technologies.
EPA, however, did not base the higher ROC BAT discharge limitation
for esters on current shale shaker technology because this does not
represent the best available technology (or best available demonstrated
technology). EPA does not believe that the improved environmental
performance of esters justifies the huge difference in pollutant
loadings between existing shale shaker technology and newer cuttings
dryer technology. Because the effluent limitations and standards
promulgated in this rule account for variability, the effluent
limitation and standards are higher than the long term average upon
which the technology is based. Here, the LTA for the esters ROC
limitation of 9.4% is 4.8%; while the LTA for the IOs ROC limitation of
6.9% is 3.82%. By contrast, the LTA for existing shale shaker
technology is 10.2%. This difference translates to 118 million pounds
per year of pollutants being discharged using the existing and new
model well counts for the selected BAT option (i.e., BAT/NSPS Option 2)
(see SBF Development Document). Further, as previously stated in the
April 2000 NODA (65 FR 21553), field results show that: (1) Cuttings
are dispersed during transit to the seabed and no cuttings piles are
formed when SBF concentrations on cuttings are held below 5%; and (2)
cuttings discharged from cuttings dryers (with SBF retention values
under 5%) in combination with a sea water flush, hydrate very quickly
and disperse like water-based cuttings. Thus, while EPA is willing to
provide additional flexibility to dischargers of ester-based fluids,
EPA believes that the appropriate technology basis that reflects BAT is
cuttings dryers technology.
EPA determined that zero discharge for BAT was technically feasible
and economically achievable because prior to the use of SBFs, the
industry was able to operate using only the traditional OBFs (based on
diesel oil and mineral oil), which are prohibited from discharge. EPA
concluded that a zero discharge BAT limitation for SBF-cuttings would
decrease the use of SBFs in favor of OBFs and WBFs. This is because a
zero discharge BAT limitation for SBF-cuttings would create an
incentive for operators to use the least expensive drilling fluids
(i.e., OBFs, WBFs) in order to minimize overall compliance costs.
EPA rejected the BAT zero discharge option for SBF-cuttings wastes
because it would result in unacceptable increases in NWQIs. Therefore,
EPA rejected the zero discharge option for SBF-cuttings wastes in U.S.
waters in the Offshore subcategory of 40 CFR part 435 (``U.S. Offshore
waters''). As previously stated in Section II.B, use of OBFs in place
of SBFs would lead to an increase in NWQIs including the toxicity of
the drilling waste. Use of WBFs in place of SBFs would generally lead
to a per well increase in pollutants discharged, an increase in NWQIs,
and an increase in aquatic toxicity. WBF drilling operations lead to
per well increases in pollutants discharged because WBFs generate six
times more washout (e.g., sloughing) of the well wall than SBFs. Also,
WBF drilling operations lead to increases in NWQIs because WBF drilling
operations generally take longer than SBF drilling operations which
lead to more air emissions and fuel usage from drilling rigs and
equipment. Aquatic toxicity generally increases when drilling fluid
manufacturers add supplements (e.g., glycols, shale inhibitors) to WBFs
for the purpose of making WBFs have technical capabilities (e.g.,
lubricity, shale suppression) similar to SBFs. EPA estimates that,
under the zero discharge option, some operators would switch to WBF
compositions with more non aqueous drilling fluid properties (e.g.,
lubricity, shale suppression), and that these WBFs would exhibit
greater aquatic toxicity.
EPA's analyses show that under the SBF-cuttings zero discharge
option as compared to current practice, for U.S. Offshore waters
existing sources, there would be an increase of 35 million pounds of
cuttings annually shipped to shore for disposal in non-hazardous
oilfield waste (NOW) sites and an increase of 166 million pounds of
cuttings annually injected. In addition, under the SBF-cuttings zero
discharge option, operators would use the more toxic OBFs. The zero
discharge option for SBF-cuttings would lead to an increase in annual
fuel usage of 358,664 BOE and an increase in annual air emissions of
5,602 tons. Finally, the SBF-cuttings zero discharge option in the U.S.
Offshore waters would lead to an increase of 51 million pounds of WBF
cuttings being discharged to U.S. Offshore waters. This pollutant
loading increase is a result of GOM operators switching from efficient
SBF drilling to less efficient WBF drilling.
EPA's analysis shows that the impacts of adequately controlled SBF
discharges to the water column and benthic environment are of limited
scope and duration. By contrast, the landfilling of OBF-cuttings is of
a longer term duration and associated pollutants may affect ambient
air, soil, and groundwater quality. EPA and DOE documented at least
five CERCLA (or ``Superfund'') sites in Louisiana and California
contaminated with oilfield wastes and more than a dozen other sites
subject to Federal or State cleanup actions.
Nonetheless, while SBF-cuttings discharge with adequate controls is
preferred over zero discharge in U.S. Offshore waters, SBF-cuttings
discharge with inadequate controls is not preferred over zero
discharge. EPA believes that to allow discharge of SBF-cuttings in U.S.
Offshore waters, there must be appropriate controls to ensure that
EPA's discharge limitations reflect the ``best available technology''
or other appropriate level of technology. EPA has worked with industry
to address the appropriate determination of PAH content, sediment
toxicity, biodegradation, quantity of SBF discharged, and formation oil
contamination that are technically available, economically achievable,
and have acceptable NWQIs. The final BAT limitations are a result of
this effort and are discussed below.
EPA is today promulgating BAT of zero discharge for SBF-cuttings
for Coastal Cook Inlet, Alaska except when Coastal Cook Inlet, Alaska,
operators are unable to dispose of their SBF-cuttings using any of the
following disposal options: (1) On-site re-injection (annular disposal
or Class II UIC); (2) re-injection using a nearby Coastal or Offshore
Class II UIC disposal well; or (3) onshore disposal using a nearby
Class II UIC disposal well or land application. Coastal Cook Inlet,
Alaska, operators are required to demonstrate to the NPDES permit
controlling authority that none of the above three disposal options are
technically feasible in order to qualify for the alternate BAT
limitation. Coastal Cook Inlet, Alaska, operators that qualify for the
alternate BAT limitation are allowed to discharge SBF-cuttings at the
same level of BAT control as operators in Offshore waters. The NPDES
permit controlling authority will use the procedure given in Appendix 1
to subpart D of 40 CFR part 435 to establish whether or not a Coastal
Cook Inlet, Alaska, operator qualifies for the
[[Page 6869]]
SBF-cuttings zero discharge exemption. As stated in Appendix 1 to
subpart D of 40 CFR part 435, the following factors are considered in
the determination of whether or not Coastal Cook Inlet, Alaska,
operators qualify for the SBF-cuttings zero discharge exemption: (1)
Inability to establish formation injection in wells that were initially
considered for annular or dedicated disposal; (2) inability to prove to
UIC controlling authority that the waste will be confined to the
formation disposal interval; (3) inability to transport drilling waste
to an offshore Class II UIC disposal well or an onshore disposal site;
and (4) whether or not there is no available land disposal facilities
(e.g., onshore re-injection, land disposal).
EPA finds that this option is technically available and
economically achievable. Operators are currently barred from
discharging OBFs, SBFs, and enhanced mineral oil based drilling fluids
under the Cook Inlet NPDES general permit (64 FR 11889). As previously
discussed in Section IV.E, EPA identified that many Cook Inlet
operators in Coastal waters are using cuttings re-injection to comply
with zero discharge disposal requirements for OBFs and OBF-cuttings.
EPA contacted Cook Inlet operators (e.g., Phillips, Unocal, Marathon
Oil) and the State regulatory agency, AOGCC, for more information on
the most recent re-injection practices of Coastal and Offshore Cook
Inlet operators. AOGCC stated that there should be enough formation re-
injection disposal capacity for the small number of non-aqueous
drilling fluid wells (5-10 wells per year) being drilled in Cook Inlet
Coastal waters. Therefore, since Coastal Cook Inlet operators are
already complying with zero discharge of OBF- and SBF-cuttings, this
option is economically achievable as there are no incremental
compliance costs.
AOGCC stated, however, that case specific limitations should be
considered when evaluating disposal options (see Section IV.E). Cook
Inlet, Alaska, operators may experience the following difficulties in
attempting to comply with a zero discharge requirement for SBFs: (1)
Inability to establish formation injection in wells that were initially
considered for annular or dedicated Class II UIC disposal; (2)
inability to prove to AOGCC's satisfaction that the waste will be
confined to the formation disposal interval; and (3) inability to
transport drilling waste to an offshore Class II UIC disposal well or
an onshore disposal site. EPA believes that while these problems are
currently not presented by drilling in Cook Inlet, they could be a
problem in the future. Further, EPA believes this to be a greater
problem in Cook Inlet where climate, tides, and its distance from
commercial disposal sites make transportation to shore less feasible
than in other offshore waters near the continental U.S. If EPA did not
provide for some exceptions within the guideline itself, and these
problems presented themselves beyond the time frame for requesting a
Fundamentally Different Factors variance (under section 301(n)(2) of
the CWA, 180 days) this would render zero discharge not achievable.
Therefore, EPA believes it is reasonable to provide for some
flexibility to the current practice of zero discharge in Cook Inlet.
EPA further finds the NWQIs of this option for Cook Inlet to be
acceptable. As previously stated, few non-aqueous drilling fluid wells
are drilled in Coastal Cook Inlet, Alaska (5-10 wells per year). EPA
finds that the small number of wells drilled per year (even if all of
them are drilled using SBF) leads to very small increases in NWQIs.
Tables 6 though 10 describe the annual air emissions and fuel usage for
the three geographic regions including Cook Inlet, Alaska. In
particular, a zero discharge requirement for SBFs and SBF-cuttings in
Cook Inlet, Alaska, would lead to an annual increase of 94 tons of air
emissions and 6,067 BOE fuel used for existing sources. EPA does not
anticipate and new sources in Cook Inlet, Alaska. Consequently, EPA
finds that the overall small increases in NWQIs from the zero discharge
option, as compared to either of the two SBF-cuttings discharge
options, in Coastal Cook Inlet, Alaska, are acceptable. The two SBF-
cuttings discharge options show little change in NWQIs as compared to
baseline (see Tables 6 though 9).
1. Stock Base Fluid Technical Availability and Economic Achievability
a. Introduction. As SBFs have developed over the past few years,
the industry has come to use mainly a limited number of primary base
fluids. These include the internal olefins, linear alpha olefins, poly
alpha olefins, paraffinic oils, C12-C14 vegetable
esters of 2-hexanol and palm kernel oil, and ``low viscosity''
C8 esters. These fluids represent virtually all the SBFs
currently used in oil and gas extraction industry. EPA collected data
on performance, environmental impact, and costs for these SBFs to
develop the effluent limitations for today's final rule. The following
definitions are used in this preamble to describe various SBFs: (1)
Internal olefin (IO) refers to a series of isomeric forms of
C16 and C18 alkenes; (2) linear alpha olefin
(LAO) refers to a series of isomeric forms of C14 and
C16 monoenes; (3) poly alpha olefin (PAO) refers to a mix
mainly comprised of a hydrogenated decene dimer
C20H62 (95%), with lesser amounts of
C30H62 (4.8%) and C10H22
(0.2%); (4) vegetable ester refers to a monoester of 2-ethylhexanol and
saturated fatty acids with chain lengths in the range C8-
C16; and (5) ``low viscosity'' ester refers to an ester of
natural or synthetic C8 fatty acids and alcohols. EPA also
has data on other SBF base fluids, such as enhanced mineral oil,
paraffinic oils (i.e., saturated hydrocarbons or ``alkanes''), and the
traditional OBF base fluids: mineral oil and diesel oil.
The stock base fluid limitations in today's rule are based on the
technology of product substitution. The promulgated limitations are
technically available because they are based on currently available
base fluids that can be used in the wide variety of drilling situations
in U.S. offshore waters. EPA anticipates that the base fluids meeting
all requirements would include vegetable esters, low viscosity esters,
and internal olefins. In addition, based on current information, EPA
believes that the stock base fluid controls on PAH content, sediment
toxicity, and biodegradation rate being promulgated today are
sufficient to only allow the discharge of only those base fluids (e.g.,
esters, internal olefins) with lower bioaccumulation potentials (i.e.,
log Kow 3 to 3.5 and log Kow> 6.5 to 7).
Therefore, EPA found it was unnecessary to promulgate a separate
limitation for bioaccumulation.
As previously stated in April 2000 (65 FR 21554), EPA considered
basing the sediment toxicity and biodegradation stock limitations and
standards solely on vegetable esters (i.e., original esters) instead of
the proposed C16-C18 IO. EPA also considered
subcategorizing the final rule to determine when vegetable esters are
not practical and when C16-C18 IOs could be used
instead. EPA considered these options due to the potential for better
environmental performance of vegetable ester-based drilling fluids. EPA
and industry analytical testing show that esters have better sediment
toxicity and biodegradation performance.
EPA rejected the option of basing sediment toxicity and
biodegradation stock limitations and standards on vegetable esters due
to several technical limitations. These technical limitations of
vegetable esters preclude their use in all areas of the GOM, Offshore
California, and Cook Inlet, Alaska. Vegetable ester technical
limitations
[[Page 6870]]
include: (1) High viscosity compared with other IO SBFs at all
temperatures, with an increasing difference as temperature decreases,
leading to lower rates of penetration in wells and greater probability
of losses due to higher equivalent circulating densities; (2) high gel
strength in risers that develops when a vegetable ester-based SBF is
not circulated; (3) a high temperature stability limit ranging from
about 225 deg.F to perhaps 320 deg.F--the exact value depends on the
detailed chemistry of the vegetable ester (i.e., the acid, the alcohol)
and the drilling fluid chemistry; (4) reduction of the thermal
stability limit through hydrolysis when vegetable esters are in contact
with highly basic materials (e.g., lime, green cement) at elevated
temperatures; and (5) less tolerance of the muds to contamination by
seawater, cement, and drill solids than is observed for IO-SBFs (Docket
No. W-98-26: Record No. IV.A.a.3, Attachment A2--``Limitations of
Esters'; Record No. IV.A.a.13, Attachments Ester-51, 52, 53, 54, 56).
EPA also rejected the option of subcategorizing the use of esters
to define drilling conditions when only esters could be allowed for a
controlled discharge. EPA could not establish a ``bright line''
rationale to define the situation where only esters should be the
benchmark fluid (i.e., only esters would be allowed for a controlled
discharge). EPA considered many of the engineering factors used for
selection of a drilling fluid (e.g., rig size and equipment; formation
characteristics; water depth and environment; lubricity, rheological,
and thixotropic requirements) and determined that this type of sub-
categorization was not possible. EPA, however, is encouraging the use
of esters by promulgating a higher ROC limitation and standard when
esters are used.
EPA also considered basing sediment toxicity and biodegradation
stock limitations and standards on low viscosity esters. Comments to
the April 2000 NODA state that laboratory analyses, which were designed
to simulate GOM conditions to which a fluid may be exposed, indicate
that low viscosity esters have the following technical properties: (1)
Similar or better viscosity than C16-C18 IOs; (2)
can be used to formulate stable low viscosity ester-based SBFs up to
300 deg.F; (3) can be used to formulate low viscosity ester-based SBFs
to 16.0+ lbs/gal mud weight; (4) can reduce oil/water ratios to 70/30,
thus reducing volumes of base fluid discharged; (5) high tolerance to
drilled solids; (6) flat gels make it easier to break circulation,
minimizing initial circulation pressures and subsequent risk of
fracture; (7) high tolerance to seawater contamination; and (8)
rheological properties can be adjusted by use of additives to suit
specific conditions (Docket No. W-98-26, Record No. IV.A.a.7). EPA also
received information on one well section drilled with low viscosity
esters. Some of the results from this low viscosity ester well section
were compared to the results from another well section in the same
location where C16-C18 IOs were used. These
results show that the low viscosity ester had: (1) Comparable or better
equivalent circulating densities (i.e., acceptable fluid properties);
and (2) faster ROP through better hole cleaning and higher lubricity
(i.e., fewer days required to drill to total depth which lead to less
NWQI and overall drilling costs). The low viscosity esters are
relatively new base fluids and have only recently been available to the
market. Despite the results from the laboratory analyses and one well
section, EPA does not believe that this is enough information to make
the determination that low viscosity esters can be used in all or
nearly all drilling conditions in the offshore U.S. waters (e.g.,
differing formations, water depths, and temperatures). Therefore, EPA
rejected the option of basing sediment toxicity and biodegradation
stock limitations and standards on low viscosity esters. EPA is
sufficiently satisfied, however, that low viscosity esters and
vegetable esters provide better environmental performance (e.g.,
sediment toxicity, biodegradation). Consequently, EPA is promulgating
higher retention on cuttings discharge limitations where esters are
used to encourage operators to use esters when possible.
b. PAH Content Technical Availability. Today's promulgated
limitation of PAH content for U.S. Offshore waters is a weight ratio
defined as the weight of PAH (as phenanthrene) per weight of the stock
base fluid sample. The PAH weight ratio is 0.001%, or 10 parts per
million (ppm). This limitation is based on the availability of base
fluids that are free of PAHs and the detection of the PAHs by EPA
Method 1654A, ``PAH Content of Oil by High Performance Liquid
Chromatography with a UV Detector.'' Method 1654A was published in
Methods for the Determination of Diesel, Mineral and Crude Oils in
Offshore Oil and Gas Industry Discharges (EPA-821-R-92-008,
incorporated by reference and available from National Technical
Information Service at (703) 605-6000). As originally proposed in
February 1999 (64 FR 5503), EPA is promulgating the use of the EPA
Method 1654A for compliance with this PAH content BAT limitation.
EPA's promulgated PAH content limitation is technically available.
Producers of several SBF base fluids have reported to EPA that their
base fluids are free of PAHs. The base fluids which suppliers have
reported are free of PAHs include IOs, LAOs, vegetable esters, low
viscosity esters, certain enhanced mineral oils, synthetic paraffins,
certain non-synthetic paraffins, and others. The use of these fluids
can accommodate the broad varieties of drilling situations faced by
industry in offshore U.S. waters (see SBF Development Document, Chapter
IV). Compliance with the stock BAT limitation and NSPS on PAH content
will be achieved by product substitution.
c. Sediment Toxicity Technical Availability. EPA is today
promulgating a sediment toxicity stock base fluid limitation that would
only allow the discharge of SBF-cuttings using SBF base fluids as toxic
or less toxic, but not more toxic, than C16-C18
IOs. Alternatively, this limitation could be expressed in terms of a
``sediment toxicity ratio'' which is defined as 10-day LC50
of C16-C18 internal olefins divided by the 10-day
LC50 of stock base fluid being tested. EPA is promulgating a
sediment toxicity ratio of less than 1.0. Compliance with this
limitation is determined by the 10-day Leptocheirus plumulosus sediment
toxicity test (i.e., ASTM E1367-92: ``Standard Guide for Conducting 10-
day Static Sediment Toxicity Tests With Marine and Estuarine Amphipods'
(incorporated by reference and available from ASTM, 100 Bar Harbor
Drive, West Conshohocken, PA 19428), supplemented with the preparation
procedure specified in Appendix 3 of Subpart A of 40 CFR part 435). As
originally proposed in February 1999 (64 FR 5503) and re-stated in
April 2000 (65 FR 21549), EPA is promulgating the use of the ASTM
E1367-92 method for compliance with this sediment toxicity BAT
limitation.
Since the February 1999 proposal, EPA and other researchers
conducted numerous 10-day L. plumulosus sediment toxicity tests on
various SBF base fluids with natural and formulated sediments. Nearly
all the SBF base fluids have lower sediment toxicity than diesel and
mineral oil. Some SBF base fluids, however, show greater sediment
toxicity than other SBF base fluids (see 65 FR 21550; Docket No. W-98-
26, Record No. IV.A.a.13). The base fluids meeting this limitation
include vegetable esters, low viscosity esters, internal olefins, and
some PAOs (see 65
[[Page 6871]]
FR 21550; Docket No. W-98-26, Record No. IV.A.a.13).
EPA finds this limit to be technically available and economically
achievable through product substitution because information in the
rulemaking record supports the findings that vegetable esters, low
viscosity esters, and internal olefins have performance characteristics
enabling them to be used in the wide variety of drilling situations in
offshore U.S. waters and meet today's promulgated limit.
EPA selected the C16-C18 IO, which is the
most popular drilling fluid in the GOM, as the basis for the sediment
toxicity rate ratio limitation instead of the vegetable ester or low
viscosity ester for several reasons: (1) EPA does not believe that
vegetable esters can be used in all drilling situations; and (2) EPA
does not have sufficient field testing information that low viscosity
esters can be used in all drilling situations (see Section V.F.1.a). In
addition, because of the uncertainty about ester performance, operators
may not be encouraged to switch from OBFs or WBFs to SBF when properly
installed and maintained. Specifically, vendor supplied data associated
with these cuttings dryer deployments suggest that the overall cuttings
dryer downtime (i.e., time when cuttings dryer equipment is not
operable) is approximately 1 to 2% (Docket No. W-98-26, Record No.
IV.A.a.6). EPA finds this small downtime percentage as acceptable.
EPA discussed how it revised the BAT/NSPS-level solids control
equipment configuration used in its analyses in the April 2000 NODA (65
FR 21559). EPA also discussed a range of management options regarding
the BAT limitation for SBF retention on SBF-cuttings: (1) Two
discharges from the BAT/NSPS-level solids control equipment
configuration (i.e., one discharge from the cuttings dryer and another
discharge from the fines removal unit); (2) one discharge from the BAT/
NSPS-level solids control equipment configuration (i.e., one discharge
from the cuttings dryer with the fines from the fines removal unit
captured for zero discharge); and (3) zero discharge of SBF-cuttings.
These three options are labeled as BAT/NSPS Option 1, BAT/NSPS Option
2, and BAT/NSPS Option 3, respectively. EPA estimates that 97% and 3%
of the total cuttings are generated by cuttings dryer and fines removal
unit, respectively.
EPA developed two numerical well averaged ROC limitations (i.e.,
one for SBFs with the stock base fluid performance similar to esters
and another for SBFs with the stock base fluid performance similar to
C16-C18 internal olefins) and based both of these
ROC limitations on the technology of only one discharge from the
cuttings dryer with the fines from the fines removal unit captured for
zero discharge (i.e., BAT/NSPS Option 2). The numerical well averaged
ROC maximum limitation for SBFs (i.e., 9.4%) with the environmental
characteristics of esters is based on a combination of data from
horizontal centrifuge, vertical centrifuge, squeeze press, and High-G
linear shaker cuttings dryer technologies. The numerical well averaged
ROC maximum limitation for SBFs (i.e., 6.9%) with the environmental
characteristics of C16-C18 internal olefins is
based on a combination of data from horizontal and vertical centrifuge
cuttings dryer technologies. EPA estimates that operators, generally
installing new equipment where none has been used in the past, will be
able to choose from among the better technologies, designs, operating
procedures, and maintenance procedures that EPA has considered to be
among the best available technologies. EPA data demonstrates that
operators properly using these cuttings dryer technologies will be able
to comply with these final ROC numerical limitations. Data submitted to
EPA show that operators using the vertical centrifuge and horizontal
centrifuge are capable of achieving the lower ROC limitation (i.e.,
6.9%). Data submitted to EPA also show that operators using the
vertical centrifuge, horizontal centrifuge, squeeze press, and High-G
linear shaker are capable of achieving the higher ROC limitation (i.e.,
9.4%). More details on the observed performance of the individual
technologies and details of calculation for the numerical limits are
presented in the SBF Statistical Support Document and SBF Development
Document.
EPA developed the two ROC limitations because EPA used a two part
approach to control SBF-cuttings discharges. The first part is the
control of which SBF are allowed for discharge through use of stock
limitations (e.g., sediment toxicity, biodegradation, PAH content,
metals content) and discharge limitations (e.g., diesel oil
prohibition, formation oil prohibition, sediment toxicity, aqueous
toxicity). The second part is the control of the quantity of SBF
discharged with SBF-cuttings. As previously stated, EPA and industry
sediment toxicity and biodegradation laboratory studies show that both
vegetable esters and low viscosity esters have better environmental
performance than all other SBF base fluids. However, because the
technical availability of product substitution with esters was not
demonstrated across the offshore subcategory, EPA rejected the option
of basing sediment toxicity and biodegradation stock limitations and
standards on vegetable esters and low viscosity esters (see V.F.1.a).
EPA is sufficiently satisfied, however, that both esters provide better
environmental performance (e.g., sediment toxicity, biodegradation).
Consequently, EPA is promulgating a higher retention on cuttings
discharge limitation to encourage operators to use esters when
possible. EPA estimates that a higher retention on cuttings discharge
limitation for esters is equivalent to the same level of control as a
lower retention on cuttings discharge limitation for all other SBFs
that have poorer sediment toxicity and biodegradation performances.
In response to the April 2000 NODA, EPA received comments from an
ester-based SBF manufacturer that EPA should create an incentive for
operators to use ester-based SBFs by basing the ROC limitation for
ester-based SBFs on baseline solids control equipment (e.g., primary
and secondary shale shakers, fines removal unit) (Docket No. W-98-26,
Record No. IV.A.a.7). In late comments, this same commentor claimed
that a ROC limitation based on any cuttings dryer technology would not
provide any incentive for the use of ester-based SBFs (Docket No. W-98-
26, Record No. IV.A.a.38). Further, they argued that the superior
laboratory performance of these ester base fluids in terms of sediment
toxicity and biodegradation justifies allowing them to be discharged
with a ROC limitation based on baseline solids control equipment. EPA
estimates that a ROC BAT limitation based on the baseline solids
control equipment is above 15.3%.
While EPA is willing to expand the technology basis to allow the
use of less effective cuttings dryers for ester-based SBFs (e.g.,
squeeze press, High-G linear shakes), EPA is unwilling to entirely
abandon the use of cuttings dryers for ester-based SBF drilling
operations. EPA is unwilling to set a higher ROC limitation for SBFs
with the environmental performance of ester-based SBFs based on
baseline solids control technology because the environmental
improvement resulting from the use of improved solids control
technology (i.e., cuttings dryers) outweighs the incremental ester
laboratory sediment toxicity and biodegradation performance over
internal olefins. Cuttings dryers promote pollution prevention through
increased re-use of drilling fluids and prevent
[[Page 6872]]
significant amounts of pollutants from being discharged to the ocean.
EPA provides for variability from the long term average (LTA) of
performance data from the candidate treatment technology or
technologies. The LTA performance of the baseline solids control
technology is 10.2%, as compared to the LTA of 4.8% based on data from
all four cutting dryer technologies. This difference translates to 118
million pounds per year of pollutants being discharged using the
existing and new model well counts for the selected BAT option (i.e.,
BAT/NSPS Option 2) (see SBF Development Document). Further, as
previously stated in the April 2000 NODA (65 FR 21553), field results
show that: (1) Cuttings are dispersed during transit to the seabed and
no cuttings piles are formed when SBF concentrations on cuttings are
held below 5%; and (2) cuttings discharged from cuttings dryers (with
SBF retention values under 5%) in combination with a sea water flush,
hydrate very quickly and disperse like water-based cuttings. Thus,
while EPA is willing to provide additional flexibility to dischargers
of ester-based fluids, EPA believes that the appropriate technology
basis that reflects BAT is cuttings dryers technology. In balancing the
environmental effects of these additional ester-based SBFs discharges
controlled with the use of baseline solids control technology against
the environmental effects of lower internal olefin-based SBFs
discharges controlled with the use of cuttings dryers, EPA has
concluded that the improvement in solids control technology leading to
lower values of ROC is a more significant factor than laboratory data
for ester base fluids showing lower sediment toxicity and higher
biodegradation.
EPA is also not convinced that the difference in ROC limitations
provides no incentive to use ester-based SBFs, as the ester-based SBF
manufacturer argues. EPA believes that the difference between 6.9% and
9.4% could provide an incentive for operators to use ester-based SBFs.
As operators have increasingly installed cuttings dryers in the GOM
(over three dozen successful deployments in the last two years), and as
any SBF discharger installs new technology to comply with the lower ROC
limitation (i.e., 6.9%), operators may find that it is worthwhile to
purchase ester-based SBFs in order to be able to operate with even a
greater margin of flexibility under a limit of 9.4% as compared to
6.9%.
As this rule is performance based, EPA is not prohibiting the
discharge of SBF-cuttings from the fines removal unit in order to
comply with the base fluid retained on cuttings discharge BAT
limitation. Operators are only required to show that the volume
weighted average of all their SBF-cuttings discharges is below the
discharge BAT limitation. EPA expects that most operators will be able
to discharge cuttings from the cuttings dryer and fines removal unit
and comply with this discharge BAT limitation. If, for example, the
average retention of SBF on SBF-cuttings from a cuttings dryer is
6.00%, the average retention of SBF on SBF-cuttings from a fines
removal unit is 12.00%, and the fines are observed to comprise 3% of
the total cuttings discharged, then the well average is 6.18% (i.e.,
(0.97) (6.00%) + (0.03)(12.00%) = 6.18%). If the well average for SBF
retention from the cuttings dryer exceeds the discharge limit then in
order to comply with this discharge BAT limitation all cuttings must be
re-injected on-site or hauled to shore for land disposal. EPA finds
that if this is the case, the limit is technologically available
because operators have transported OBFs to shore since 1986 and have
transported WBFs that do not meet the existing effluent limitations and
standards since 1993.
EPA finds that both ROC limitations (i.e., 6.9%, 9.4%) are
technically available to the industry because they are based on product
substitution and a statistical analysis of ROC performance from
drilling conditions throughout offshore waters. The BAT limitations for
controlling the amount of SBF discharged with SBF-cuttings are
calculated such that nearly all well averages for retention are
expected to meet these values using the selected technologies without
any additional attention to design, operation, or maintenance. EPA data
demonstrates that operators properly using these cuttings dryer
technologies will be able to comply with these final ROC numerical
limitations because: (1) These limits allow for variation in formation
characteristics that may not exist in the United States; (2) operators,
generally installing new equipment where none has been used in the
past, will be able to choose from among the better technologies,
designs, operating procedures, and maintenance procedures that EPA
considers to be among the best available technologies; and (3)
operators may elect to use SBFs with the stock base fluid performance
of esters and horizontal or vertical centrifuge cuttings dryers to
achieve a ROC well average well below the 9.4% ROC limitation.
Data used in the calculation of the numerical limits exclude
retention results submitted without backup calculations (i.e., without
raw retort data) and include data from drilling operations in foreign
waters (e.g., Canada). EPA excluded ROC data without raw retort data
(e.g., masses and volumes of cuttings samples and recovered liquids
taken during the retort method by the field technician) due to concerns
over data quality (e.g., no independent method to check data quality).
EPA included ROC data from Canadian drilling operations to incorporate
the variability of cuttings dryer performance in harder and less
permeable formations that generally lead to higher ROC values. EPA
estimates that the major factors leading to higher ROC values for all
solids control equipment include: (1) Slower rates of penetration; (2)
formations that are harder and less permeable; and (3) selection of
certain drill bits. The Canadian ROC data come from formations that are
generally much harder and less permeable than what is observed in the
GOM. These harder formations generally lead to slower rates of
penetration. The less permeable Canadian formations lead to fewer
downhole losses of SBF. Downhole losses require the addition of fresh
SBF to maintain volume requirements for the active mud system. These
additions of fresh SBF to the active mud system help control the
potential of build-up of fines. In addition, operators often use PDC
drill bits in order to grind through the hard Canadian formations. This
grinding action leads to smaller cuttings than is what is observed in
the GOM. The smaller cuttings have more surface area for SBF than
larger cuttings and generally have higher ROC values. Consequently,
EPA's use of Canadian data in its analyses incorporate sufficient
variability to model the formations in GOM, Offshore California, Cook
Inlet, Alaska, and other offshore U.S waters where EPA does not have
ROC data.
EPA finds that both well-average discharge BAT ROC limitations
(e.g., 6.9%, 9.4%) for base fluid on wet cuttings are economically
achievable. According to EPA's analysis, in addition to reducing the
discharge of SBFs associated with the cuttings, EPA estimates that this
control will result in a net savings of $48.9 million ($1999) dollars
per year. This savings results, in part, because the value of the SBF
recovered is greater than the cost of installation of the improved
solids control technology.
EPA concluded that a zero discharge requirement for SBF-cuttings
from
[[Page 6873]]
existing sources and the subsequent increase use of OBFs and WBFs would
result in: (1) Unacceptable NWQIs; and (2) more pollutant loadings to
the ocean due to operators switching from SBFs to less efficient WBFs
(see Sections II.B and V.F). For these reasons, EPA rejected the BAT
zero discharge option for SBF-cuttings from existing sources.
EPA also requested comments in the April 2000 NODA (65 FR 21570) on
the issue of rig compatibility with the installation of cuttings dryers
(e.g., vertical or horizontal centrifuges, squeeze press mud recovery
units, High-G linear shakers). EPA received general information on the
problems and issues related to cuttings dryer installations from API/
NOIA stating that not all rigs are capable of installing cuttings
dryers (Docket No. W-98-26, Record No. IV.A.a.13). In late comments,
some industry commentors asserted that 48 of the 223 GOM drilling rigs
are not capable of having a cuttings dryer system installed due to
either rig space and/or rig design without prohibitive costs or rig
modifications (Docket No. W-98-26, Record No. IV.B.b.33). Upon a
further, more extensive review of GOM rigs, these same commentors
asserted that 30 of 234 GOM drilling rigs are not capable of having a
cuttings dryer system installed due to either rig space and/or rig
design without prohibitive costs or rig modifications (Docket No. W-98-
26, Record No. IV.B.b.34). EPA also received late comments from one
operator, Unocal, stating that 36 of 122 Unocal wells drilled between
late 1997 and mid-2000 were drilled with rigs that do not have 40 foot
x 40 foot space available which they assert is necessary for a
cuttings dryer installation (Docket No. W-98-26, Record No. IV.B.b.31).
The API/NOIA rig survey and the Unocal rig survey identified most of
the same rigs as unable to install cuttings dryers. However, two rigs
(i.e., Parker 22, Nabors 802) identified in the Unocal rig survey as
having no space for a cuttings dryer installation were identified in
the API/NOIA rig survey as each having a previous cuttings dryer
installation. Unocal requested in late comments that EPA subcategorize
certain rigs from being subject to the retention limit or that these
rigs be able to discharge SBFs using performance that reflects current
shale shaker technology (Docket No. W-98-26, Record No. IV.A.a.36).
Based on the record, EPA finds that current space limitations for
cuttings dryers do not require a 40 foot x 40 foot space.
Specifically, EPA has in the record information gathered during EPA's
October 1999 site visit and information supplied by API/NOIA, MMS, and
equipment vendors. EPA received information from a drilling fluid
manufacturer and cuttings dryer equipment vendor, M-I Drilling Fluids,
stating that they are not aware of any GOM rig not capable of
installing a cuttings dryer (Docket No. W-98-26, Record No. IV.B.b.32).
Another cuttings dryer equipment vendor, JB Equipment, asserted that
there are at most only a few rigs that pose questionable installation
problems and that they have yet to survey a rig that they could not
install a cuttings dryer (Docket No. W-98-26, Record No. IV.B.b.48). JB
Equipment also stated that inexperience with cuttings dryer
installations may inhibit the ability of operators or rig owners to
properly judge whether a cuttings dryer can be installed. JB Equipment
cited an example where the operator concluded that a cuttings dryer
could not be installed on a rig (Nabors 803) while JB Equipment
surveying efforts identified the cuttings dryer installation for the
same rig as one of the simplest installations JB Equipment performs.
MMS also concluded that rigs do not need a 40 foot x 40 foot space to
install a cuttings dryer and that, with the exception of a few jackup
and platform rigs, there should not be any significant issues related
to installing cuttings dryers on OCS drilling rigs (Docket No. W-98-26,
Record No. IV.B.a.28). API/NOIA estimated that 150 square feet are
required for a cuttings dryer installation in order to meet the ROC BAT
limitation and NSPS (Docket No. W-98-26, Record No. IV.A.a.13). EPA
also estimates that the minimum height clearance for a typical cuttings
dryer installation is 6 feet (see SBF Development Document). The API/
NOIA estimate is based on the installation of a horizontal centrifuge
cuttings dryer (i.e., MUD-6). The Unocal estimate is based on the
vertical centrifuge cuttings dryer and is also characterized by other
industry representatives and MMS as too high (Docket No. W-98-26,
Record No. IV.B.b.34; Record No. IV.B.a.28). EPA's estimate of a
typical vertical centrifuge installation is 15 feet x 15 feet (i.e.,
225 square feet) with a minimum height clearance of 11 feet (see SBF
Development Document). EPA based the ROC BAT limitation and NSPS (e.g.,
6.9%) on the use of both these cuttings dryers for SBFs with the stock
limitations of C16-C18 IOs. Based on comments
from operators, equipment vendors, and MMS, EPA believes that most of
these shallow water rigs have the requisite 150-225 square feet
available to install a cuttings dryer (see SBF Development Document).
Therefore, EPA finds that operators are not required to have a 1,600
square foot space for a cuttings dryer installation in order to meet
the ROC BAT limitation and NSPS. Proper spacing and placement of
cuttings dryers in the solids control equipment system should prevent
installation problems.
Because of the large discrepancy between EPA's record information
and the space requirements asserted by the commenter (1,600 square feet
versus EPA's 225 square feet + 11 feet in height for the vertical
centrifuge or 150 square feet + 6 feet in height for the horizontal
centrifuge--MUD-6), EPA does not necessarily believe that there are as
many wells that cannot install cuttings dryers as the commentor
(Unocal) claims. Further, based on scant detail supporting these
assertions, and their lateness in the process, EPA has no basis upon
which to assess them or verify them.
Moreover, EPA does not believe that it has enough information to
reasonably subcategorize these facilities, nor did it have time to
provide public notice of how it would define such a subcategory, given
the court-ordered deadline for this rule. EPA does not believe that
basing a subcategory by specifying a space requirement alone (e.g.
operators that do not have a certain amount of deck space available on,
below or adjacent to the deck would not be subject to this requirement)
would be sufficient to prevent operators from configuring their other
equipment in a manner that would enable them to fit into the
subcategory. Such an exception might also lead to operators to make
other assertions justifying that they should be included (e.g., that
while they have a certain amount of space available, safety reasons
prevent placement of the technology on the rig). Without a solution to
these issues, EPA is concerned that such a subcategorization would
potentially be too broad and be unworkable.
For these reasons, EPA believes that the appropriate way to handle
these concerns is through the fundamentally different factors (FDF)
variance process. This process, provided for under CWA section 301(n),
would allow operators to submit supporting data and information to EPA
and would give the public the opportunity to comment on that data to
determine whether an FDF is truly warranted for that drilling facility.
EPA has authority over owners and operators, who are both dischargers,
but the NPDES regulations require the operator to apply for the NPDES
permit: ``When a facility or activity is owned by one person but is
operated by another person, it is the operator's duty to obtain
[[Page 6874]]
a permit,'' (see 40 CFR 122.21(b)). Thus, mobile drill rig
``operators'' as dischargers can apply for FDFs (see 40 CFR 125.32;
122.21(b)).
EPA notes that the ROC limitations and standards do not preclude
the use of SBFs if an operator cannot meet them if the operator can
meet zero discharge through re-injection or shipment to shore.
Historically, dischargers have used water-based fluids in shallow water
wells and this may also be an option. EPA considers controlled WBF
discharges preferable to uncontrolled SBF discharges. EPA examined the
NWQIs associated with these zero discharge operations as acceptable
(see SBF Development Document). The NWQIs of zero discharge for the
shallow water wells are much smaller that those associated for the
entire region covered by this rule. Further, while a SBF-cuttings
discharge option with adequate controls is preferred over the zero
discharge option for SBF-cuttings in U.S. Offshore waters, a SBF-
cuttings discharge option with inadequate controls is not preferred
over zero discharge. The retention limit is a very important control
because it controls: (1) The amount of SBF discharged to the ocean; (2)
the biodegradation rate of discharged SBF; and (3) the potential for
SBF-cuttings to develop cuttings piles and mats which are detrimental
to the benthic environment. In short, EPA does not view existing shale
shaker technology (or performance of other technology equivalent to
shale shaker technology) to constitute the appropriate level of control
under BAT or BADT (NSPS).
EPA has also decided that solids accumulated at the end of the well
(``accumulated solids'') and wash water used to clean out accumulated
solids or on the drill floor are associated with drill cuttings and are
therefore not controlled by the zero discharge requirement for SBFs not
associated with drill cuttings (see Section V.C). EPA has decided to
control accumulated solids and wash water under the discharge
requirements for cuttings associated with SBFs. The amount of SBF base
fluid discharged with discharged accumulated solids will be estimated
using procedures in Appendix 7 to subpart A of 40 CFR part 435 and
incorporated into the base fluid retained on cuttings numeric
limitation or standard. The source of the pollutants in the accumulated
solids and associated wash water are drill cuttings and drilling fluid
solids (e.g., barite). The drill cuttings and drilling fluid solids can
be prevented from discharge with SBF-cuttings due to equipment design
(e.g., sand traps, sumps) or improper maintenance of the equipment
(e.g., failing to ensure the proper agitation of mud pits). EPA agrees
with commentors that the discharge of SBF associated with accumulated
solids in the SBF active mud system and the associated wash water is
normally a one-time operation performed at the completion of the SBF
well (e.g., cleaning out mud pits and solids control equipment).
The quantity of SBF typically discharged with accumulated solids
and wash water is relatively small. The SBF fraction in the 75 barrels
of accumulated solids is approximately 25% and generally only very
small quantities of SBF are contained in the 200 to 400 barrels of
associated equipment wash water. Current practice is to retain
accumulated solids for zero discharge or recover free oil from
accumulated solids prior to discharge. Since current practice is to
recover free oil and discharge accumulated solids, the controlled
discharge option for SBF-cuttings represents current practice and is
economically achievable. Moreover, recovering free oil from accumulated
solids prior to discharge has no unacceptable NWQIs. EPA defines
accumulated solids and wash water as associated with drill cuttings.
Therefore, operators will control these SBF-cuttings wastes using the
SBF stock limitations and cuttings discharge limitations. As compliance
with EPA's SBF stock limitations and cuttings discharge limitations
does not require the processing of all SBF-cuttings wastes through the
solids control technologies (e.g., shale shakers, cuttings dryers,
fines removal units), operators may or may not elect to process
accumulated solids or wash water through the solids control
technologies.
EPA is also promulgating a set of BMPs for operators to use that
demonstrates compliance with the numeric ROC limitation and therefore
reduces the retort monitoring otherwise required to determine
compliance with the numeric ROC limitation. This option combines the
set of BMPs that represent current practice with BMPs that are
associated with the use of improved solids control technology. This
option is technologically available and economically achievable for the
same reasons that apply to compliance with the ROC numerical
limitations. Examples of BMPs that represent current practices are, for
example, use of mud guns, proper mixing procedure, elimination of
settling places for accumulated solids. Examples of BMPs associated
with the use of the new solids control technology are, for example,
operating cuttings dryers in accordance with the manufacturer's
specifications and maintaining a certain mass flux. If operators elect
to use this BMP option, they will be required to demonstrate compliance
through limited retort monitoring of cuttings and additional BMP
paperwork. Paperwork requirements are detailed in Appendix 7 of subpart
A of 40 CFR part 435. Paperwork cost and burden estimates are detailed
in Section IX.D of the preamble.
d. Sediment Toxicity of SBF Discharged with Cuttings. As originally
proposed in February 1999 (64 FR 5491) and re-stated in April 2000 (65
FR 21557), EPA is today promulgating a BAT limitation to control the
maximum sediment toxicity of the SBF discharged with cuttings. This BAT
limitation controls the sediment toxicity of the SBF discharged with
cuttings as a non-conventional pollutant parameter and as an indicator
for other pollutants in the SBF discharged with cuttings. Some of the
toxic, priority, and non-conventional pollutants in the SBF discharged
with cuttings may include: (1) The base fluids such as enhanced mineral
oils, internal olefins, linear alpha olefins, poly alpha olefins,
paraffinic oils, C12-C14 vegetable esters of 2-
hexanol and palm kernel oil, ``low viscosity'' C8 esters,
and other oleaginous materials; (2) barite which is known to generally
have trace contaminants of several toxic heavy metals such as mercury,
cadmium, arsenic, chromium, copper, lead, nickel, and zinc; (3)
formation oil which contains toxic and priority pollutants such as
benzene, toluene, ethylbenzene, naphthalene, phenanthrene, and phenol;
and (4) additives such as emulsifiers, oil wetting agents, filtration
control agents, and viscosifiers.
The sediment toxicity of the SBF discharged with cuttings is
measured by the modified sediment toxicity test (i.e., ASTM E1367-92:
``Standard Guide for Conducting 10-day Static Sediment Toxicity Tests
With Marine and Estuarine Amphipods'' (incorporated by reference and
available from ASTM, 100 Bar Harbor Drive, West Conshohocken, PA
19428), supplemented with the preparation procedure specified in
Appendix 3 of subpart A of 40 CFR part 435) using a natural sediment or
formulated sediment, 96-hour testing period, and Leptocheirus
plumulosus as the test organism. EPA is today promulgating a sediment
toxicity limitation for the SBF discharged with cuttings at the point
of discharge that would only allow the discharge of SBF-cuttings using
SBFs as toxic or less toxic, but not more toxic, than C16-
C18
[[Page 6875]]
IOs SBFs. Alternatively, this limitation could be expressed in terms of
a ``SBF sediment toxicity ratio'' which is defined as 96-hour
LC50 of C16-C18 internal olefins SBF
divided by the 96-hour LC50 of the SBF being discharged with
cuttings at the point of discharge. EPA is promulgating a SBF sediment
toxicity ratio of less than 1.0.
EPA finds that the sediment toxicity test at the point of discharge
is practical as an indicator of the sediment toxicity of the drilling
fluid at the point of discharge. As previously stated, establishing
discharge limits on toxicity encourages the use of less toxic drilling
fluids and additives. The modifications to the sediment toxicity test
include shortening the test to 96-hours. Shortening the test will allow
operators to continue drilling operations while the sediment toxicity
test is being conducted on the discharged drilling fluid. Moreover,
discriminatory power is substantially reduced for the 10-day test on
drilling fluid as compared to the 96-hour test (i.e., the 10-day test
is of lower practical use in determining whether a SBF is substantially
different from OBFs). Finally, operators discharging WBFs are already
complying with a biological test at the point of discharge, the 96-hour
SPP toxicity test, which tests whole WBF aquatic toxicity using the
test organism Mysidopsis bahia.
The promulgated sediment toxicity limitation would be achievable
through product substitution. EPA anticipates that the base fluids
meeting the sediment toxicity limitation would include vegetable
esters, low viscosity esters, and internal olefins. The reference
C16-C18 IOs SBF will be formulated to meet the
specifications in Table 1 and also contained in Appendix 8 of subpart A
of 40 CFR part 435. The sediment toxicity discharge limitation is
technically and economically achievable because it is based on
currently available base fluids that can be used and are used across
the wide variety of drilling situations found in U.S. offshore waters.
EPA estimates minimal monitoring costs associated with this limitation.
Additionally, the sediment toxicity discharge limitation will not lead
to an increase of NWQIs.
Table 1.--Properties for Reference C16-C18 IOs SBF Used in Discharge Sediment Toxicity Testing
----------------------------------------------------------------------------------------------------------------
Reference C16-C18 ISOs
Mud weight of SBF discharged with cuttings (pounds per gallon) Reference C16-C18 IOs SBF synthetic to water
SBF (pounds per gallon) ratio (%)
----------------------------------------------------------------------------------------------------------------
8.5-11........................................................ 9.0 75/25
11-14......................................................... 11.5 80/20
> 14.......................................................... 14.5 85/15
================================================================================================================
Plastic Viscosity (PV), centipoise (cP)....................... ....................... 12-30
Yield Point (YP), pounds/100 sq. ft........................... ....................... 10-20
10-second gel, pounds/100 sq. ft.............................. ....................... 8-15
10-minute gel, pounds/100 sq. ft.............................. ....................... 12-30
Electrical stability, V....................................... ....................... > 300
----------------------------------------------------------------------------------------------------------------
G. NSPS Technology Options Considered and Selected for Drilling Fluid
Associated with Drill Cuttings
The general approach followed by EPA for developing NSPS options
was to evaluate the best demonstrated SBFs and processes for control of
priority toxic, non-conventional, and conventional pollutants.
Specifically, EPA evaluated the technologies used as the basis for BPT,
BCT and BAT. The Agency considered these options as a starting point
when developing NSPS options because the technologies used to control
pollutants at existing facilities are fully applicable to new
facilities.
EPA has not identified any more stringent treatment technology
option which it considered to represent NSPS level of control
applicable to the SBF-cuttings wastestream. Further, EPA has made a
finding of no barrier to entry based upon the establishment of this
level of control for new sources. Therefore, EPA is promulgating that
NSPS be established equivalent to BPT and BAT for conventional,
priority, and non-conventional pollutants. EPA concluded that NSPS are
technologically and economically achievable for the same reasons that
BAT is available and BPT is practical. EPA also concluded that NWQIs
are reduced under the selected NSPS for new wells due to the increased
efficiency of SBF drilling.
EPA concluded that a zero discharge requirement for SBF-cuttings
from new sources and the subsequent increased use of OBFs and WBFs
would result in: (1) unacceptable NWQIs; and (2) more pollutant
loadings to the ocean due to operators switching from SBFs to less
efficient WBFs (see Sections II.B and V.F).
For the same reasons that the BAT limitations promulgated in
today's rule are technologically and economically achievable, the
promulgated NSPS are also technologically and economically achievable.
EPA's analyses show that under the SBF zero discharge option for all
areas as compared to current practice as a basis for new source
standards there would be an increase of 3.4 million pounds of cuttings
annually shipped to shore for disposal in NOW sites and an increase of
10.2 million pounds of cuttings annually injected. This zero discharge
option would lead to an increase in annual fuel use of 18,067 BOE and
an increase in annual air emissions of 528 tons. Finally, the SBF zero
discharge option for the GOM would lead to an increase of 7.5 million
pounds of WBF-cuttings being discharged to U.S. Offshore waters. This
pollutant loading increase is a result of operators in U.S. Offshore
waters (in the GOM) switching from efficient SBF drilling to less
efficient WBF drilling. EPA found these levels of NWQIs unacceptable
and rejected the NSPS zero discharge option for SBF-cuttings from new
sources, except in Coastal Cook Inlet, Alaska.
H. PSES and PSNS Technology Options
EPA is not establishing pretreatment standards for the facilities
covered by this rule. Based on information in the record, EPA has not
identified any existing offshore or Cook Inlet coastal oil and gas
extraction facilities that discharge SBF and SBF-cuttings to publicly
owned treatment works (POTWs), nor are any new facilities projected to
direct these wastes in such manner.
[[Page 6876]]
I. Best Management Practices (BMPs) to Demonstrate Compliance with
Numeric BAT Limitations and NSPS for Drilling Fluid Associated with
Drill Cuttings
Sections 304(e), 308(a), 402(a), and 501(a) of the CWA authorize
the Administrator to prescribe BMPs as part of effluent limitations
guidelines and standards or as part of a permit (see Section II.A.7).
The BMP alternatives to numeric limitations and standards in this final
rule are directed, among other things, at preventing or otherwise
controlling leaks, spills, and discharges of toxic and hazardous
pollutants in SBF cuttings wastes (see 65 FR 21569 for a list of the
toxic and hazardous pollutants controlled by these BMPs).
As discussed in the April 2000 NODA (65 FR 21568), EPA considered
three options for the final rule for the BAT limitation and NSPS
controlling SBF retained on discharged cuttings: (1) A single numeric
discharge limitation with an accompanying compliance test method; (2)
allowing operators to choose either a single numeric discharge
limitation with an accompanying compliance test method, or as an
alternative, a set of BMPs that employs limited cuttings monitoring; or
(3) allowing operators to choose either a single numeric discharge
limitation with an accompanying compliance test method or an
alternative set of BMPs that employ no cuttings monitoring. Under the
third BMP option for SBF-cuttings (i.e., cuttings discharged and not
monitored), EPA also considered whether to require as part of the BMP
option, the use of a cuttings dryer as representative of BAT/NSPS or to
make the use of a cuttings dryer optional.
EPA selects the second BMP option (i.e., allowing operators to
choose either a single numeric discharge limitation with an
accompanying compliance test method, or as an alternative, a set of
BMPs that employs limited cuttings monitoring) in the final rule. EPA
selects this option as it provides for a reasonable level of
flexibility and is based on quantifiable performance measures. EPA
analyses show that cuttings monitoring for the first third of the SBF
footage drilled for a SBF well interval is a reliable indicator of the
remaining two-thirds of the SBF-interval (see SBF Statistical Support
Document; Docket No. W-98-26, Record No. III.B.a.18; Record No.
III.B.b.15). Procedures for demonstrating compliance with the selected
BMP option are given in Appendix 7 to subpart A of part 435.
For the final rule, EPA did not have enough data from across a wide
variety of drilling conditions (e.g., formation, water depth, rig size)
to demonstrate that BMPs without cuttings monitoring are equivalent to
a numeric ROC limitation or standard. EPA is also concerned that a set
of BMPs without cuttings monitoring is not as objective to enforce.
This is because with a numeric limitation or with the selected BMP
option with reduced cuttings monitoring, operators will need to keep
records demonstrating compliance with the numeric limitation. By
contrast, under a BMP option with no numeric limit, there is no
objective performance measure. This presents a particular problem
offshore, where real-time inspections are not as practical as on land
based industries. Therefore, EPA rejected the third BMP option and
cuttings dryer sub-option for SBF-cuttings (i.e., allowing operators to
choose either a single numeric discharge limitation with an
accompanying compliance test method or an alternative set of BMPs that
employ no cuttings monitoring). EPA concluded that BMP option one and
BMP option two demonstrate the same level of compliance with the well
averaged ROC limitation and standard (see SBF Statistical Support
Document). Therefore, EPA selected BMP option two over BMP option one
to provide operators with greater flexibility to demonstrate compliance
with the well averaged ROC limitation and standard.
The BMP option promulgated in this final rule includes information
collection requirements that are intended to control the discharges of
SBF in place of numeric effluent limitations and standards. These
information collection requirements include, for example: (1) Training
personnel; (2) analyzing spills that occur; (3) identifying equipment
items that might need to be maintained, upgraded, or repaired; (4)
identifying procedures for waste minimization; (4) performing
monitoring (including the operation of monitoring systems) to establish
equivalence with a numeric cuttings retention limitation and to detect
leaks, spills, and intentional diversion; and (5) generally to
periodically evaluate the effectiveness of the BMP alternatives.
BMP option two also requires operators to develop and, when
appropriate, amend plans specifying how operators will implement BMP
option two, and to certify to the permitting authority that they have
done so in accordance with good engineering practices and the
requirements of the final regulation. The purpose of those provisions
is, respectively, to facilitate the implementation of BMP option two on
a site-specific basis and to help the regulating authorities to ensure
compliance without requiring the submission of actual BMP Plans.
Finally, the recordkeeping provisions are intended to facilitate
training, to signal the need for different or more vigorously
implemented BMP alternatives, and to facilitate compliance assessment.
Details on burden and cost estimates associated with these additional
paperwork requirements are discussed in Section IX.D.
VI. Costs and Pollutant Reductions for Final Regulation
A. Compliance Costs
EPA has analyzed the compliance costs and incremental compliance
costs or savings beyond current industry practices and requirements, as
well as pollutant loadings and incremental loadings or reductions, EPA
has performed these analyses for the Gulf of Mexico, offshore
California, and coastal Cook Inlet, Alaska, for baseline (current)
costs and three control option costs. (Compliance costs were not
developed for other offshore regions in Alaska where oil and gas
production activity exists because discharges of drill cuttings is not
expected to occur in these areas.) The three technology-based options
considered are: (1) BAT/NSPS Option 1 (controlled discharge option with
discharges from the cuttings dryer and fines removal unit); (2) BAT/
NSPS Option 2 (controlled discharge option with discharges from the
cuttings dryer but not the fines removal unit); and (3) BAT/NSPS Option
3 (Zero Discharge Option). Compliance costs/savings and pollutant
increases/reductions are based on: (1) Projected annual drilling
activity in the three geographic regions; (2) model well volumes and
waste characteristics; and (3) technology and monitoring costs.
The compliance cost analysis begins with the development of defined
populations of wells on a regional and well-type basis, develops per-
well estimates from an analysis of line-item costs, and then aggregates
costs into total regional and well-type costs by applying per well
costs to appropriate populations of wells. EPA estimates baseline
compliance costs for current industry waste management practices and
for compliance with each regulatory option. EPA then calculated
incremental compliance costs, which reflect the difference between
compliance costs for a regulatory option and baseline compliance costs
and the net compliance costs or savings which incorporate the costs
along with savings realized by recovering drilling fluids and more
efficient drilling. Tables 2 and
[[Page 6877]]
3, for existing and new sources respectively, list the total annual
baseline costs, compliance costs, incremental compliance costs, cost
savings, and net incremental compliance costs, calculated for each
geographic area and regulatory option.
1. Large Volume Discharges
BILLING CODE 6560-50-U
[[Page 6878]]
[GRAPHIC] [TIFF OMITTED] TR22JA01.154
[[Page 6879]]
[GRAPHIC] [TIFF OMITTED] TR22JA01.155
[GRAPHIC] [TIFF OMITTED] TR22JA01.156
[[Page 6880]]
[GRAPHIC] [TIFF OMITTED] TR22JA01.157
2. Small Volume Discharges
As previously stated, EPA learned that SBF is controlled with zero
discharge at the drill floor, in the form of vacuums and sumps to
retrieve spilled fluid and associated wash water. EPA also learned that
approximately 75 barrels of fine solids and barite, which have an
approximate SBF content of 25%, can accumulate in the dead spaces of
the mud pit, sand trap, and other equipment in the drilling fluid
circulation system. Current practice is to either wash these solids out
with water for overboard discharge, or to retain the waste solids for
disposal. Several hundred barrels (approximately 200 to 400 barrels) of
water are used to wash out the mud pits. Industry representatives also
indicated to EPA that those oil and gas extraction operations that
discharge wash water and accumulated solids first recover free SBF.
No additional costs were considered for controlling the minor
spills of SBF (e.g., 5 gallons spilled during each drill string
connection or disconnection) at the drill floor as: (1) Zero discharge
practices for recovering SBF at the drill floor during drilling are the
current practice; and (2) current practice is also to recover free SBF
from the wash water used at the drill floor. Additionally, since
current practice is to first recover free SBF from accumulated solids
and discharge the accumulated solids with wash water, no additional
costs were
[[Page 6881]]
considered for controlling these discharges.
EPA did not select zero discharge for management of these
accumulated solids and associated wash water. EPA is defining these
wastes as being associated with SBF-cuttings and subject to the same
requirements as other SBF discharges associated with SBF-cuttings. In
particular, the final rule requires operators to first recover free oil
from any accumulated solids or associated wash water prior to
discharging the accumulated solids and associated wash water. These
practices are related to the current BPT limitations (i.e., no
discharge of free oil) and current industry practice using solids
control equipment in order to comply with the no free oil (sheen test)
and SPP toxicity requirements. Accordingly, the requirement to recover
free oil from accumulated solids and associated wash water prior to
discharge is technologically and economically achievable with no
additional NWQIs. Retort monitoring will also be performed on the
accumulated solids and the retort monitoring results will be
incorporated into the overall well-average SBF retained on cuttings
value as described in Appendix 7 of Subpart A of 40 CFR 435.
B. Pollutant Reductions
The methodology for estimating pollutant loadings and incremental
pollutant loadings (reductions) effectively parallels that of the
compliance cost analysis. The pollutant loadings analysis uses data
from EPA and industry sources that quantify the pollutant
characteristics of drilling fluids and cuttings waste streams
(typically in, or converted to, a per barrel basis). Waste volumes for
the four model well types (DWD, DWE, SWD, SWE) are coupled with these
per barrel pollutant quantities to obtain per well estimates of
pollutant loadings. These per well estimates are then coupled with the
same well count data as used in the cost analysis to derive well type
and aggregate regional pollutant loadings for the baseline and all
options. Similar to the cost analysis, incremental loadings (or
removals) are obtained by difference between the estimated loadings of
each option less baseline loadings, at both the BAT and NSPS level of
control. This methodology is presented in more detail in the SBF
Development Document.
The loadings and non-water quality impacts of wastes subject to
zero discharge limitations by this rule are important factors in its
development. Zero discharge wastes have two fates: they are injected
into sub-seabed formations onsite or they are transported to shore for
disposal via land farming or injection. The allocation of zero
discharge wastes between onsite injection versus onshore disposal
follow the same well type and regional assumptions as were used for the
cost analysis. Zero discharge loadings (removals) are determined
identically to discharge loadings; they are presented in detail in the
Development Document and are summarized below.
Table 4 presents a summary of industry-wide results, by region, for
BAT baseline loadings, both discharge options, and the zero discharge
option, as well as their incremental loadings (removals). Table 5
presents this information for new sources.
The BCT cost test evaluates the reasonableness of BCT candidate
technologies as measured from BPT level compliance costs and pollutant
reductions. The proposed BCT level of regulatory control is equivalent
to the BPT level of control for both the discharge options and the zero
discharge option. If there is no incremental difference between BPT and
BCT, there is no cost to BCT and thus the option passes both BCT cost
tests.
[[Page 6882]]
[GRAPHIC] [TIFF OMITTED] TR22JA01.158
[[Page 6883]]
Table 5.--Summary Annual SBF Pollutant Loadings, New Sources
[In pounds/year]
------------------------------------------------------------------------
SBF pollutant loadings
Technology basis (reductions)--Gulf of
Mexico
------------------------------------------------------------------------
Baseline/Current Practice Technology Loadings:
Discharge with LTA of 10.2% SBF ROC....... 17,405,127
Discharge of WBF and cuttings............. 92,903,606
Discharge of OBF.......................... 0
-------------------------
Total Baseline Loadings................. 110,308,733
=========================
Technology Option Loadings:
BAT/NSPS Option 1.........................
Discharge with LTA of 4.03% SBF ROC....... 20,241,106
Discharge of WBF and cuttings............. 87,462,923
Discharge of OBF.......................... 0
-------------------------
Total NSPS 1 Loadings................... 107,704,029
=========================
BAT/NSPS Option 2.........................
Discharge with LTA of 3.82% SBF ROC....... 19,722,488
Discharge of WBF and cuttings............. 87,462,923
Discharge of OBF.......................... 0
-------------------------
Total NSPS 2 Loadings................... 107,185,411
=========================
BAT/NSPS Option 3--Zero Discharge.........
Discharge of SBF.......................... 0
Discharge of WBF and cuttings............. 100,387,607
Discharge of OBF.......................... 0
-------------------------
Total NSPS 3 Loadings................... 100,387,607
=========================
Incremental Technology Option Loadings
(Reductions):
BAT/NSPS Option 1: Discharge with 4.03% (2,604,704)
retention of SBF on cuttings.............
BAT/NSPS Option 2: Discharge with 3.82% (3,123,322)
retention of SBF on cuttings.............
BAT/NSPS Option 3: Zero Discharge of SBF- (9,921,126)
wastes via land disposal or onsite
injection................................
------------------------------------------------------------------------
Note: EPA estimates the following GOM WBF/OBF/SBF new sources: Baseline--
38/2/20; BAT/NSPS Option 1 & 2--35/1/24; and BAT/NSPS Option 3--42/15/
3. EPA estimates no new sources for Offshore California or Cook Inlet,
AK.
Note: The following terms are used in this table: long-term average
(LTA) and retention on cuttings (ROC).
VII. Economic Impacts of Final Regulation
EPA evaluated the economic effects of the options considered for
today's regulation. The methodology and results are presented in detail
in the SBF Economic Analysis (EPA-821-B-00-012). The following
discussion presents a summary of that analysis and its conclusions.
Small business impacts are summarized below and in Section IX.B.
Environmental justice issues are summarized in Section IV.C.
A. Impacts Analysis
EPA examined the potential impacts of the rule several ways:
effects on drilling well costs, changes to financial performance of
drilling facilities and production, impacts on small firms, and
secondary impacts. The economic methodology used to examine potential
impacts on drilling well costs, firms, and secondary impacts is the
same as that used for the February 1999 proposal (see 64 FR 5521-5527;
February 1999 proposal Economic Analysis (EPA-821-B-98-020)).
In response to comments and new data, EPA developed a series of
economic models for existing and new deep water projects in the Gulf of
Mexico similar to those used for the Offshore and Coastal rules (see 58
FR 12454-12512 and 61 FR 66086-66130). This additional analysis is
discussed in the April 2000 NODA (65 FR 21558). The models focus on the
deep water Gulf because it is the region with the highest level of
current drilling with and future interest in drilling with SBFs. The
economic models are based on a cash flow approach. Revenues are based
on an assumed price of oil, current and projected production of oil and
gas, well production decline rates, and royalty rates. Operating costs
are based on an assumed cost per BOE produced. The models are based on
data from MMS and industry (see Summary of Data to be Used In Economic
Modeling for more details on the methodology, data, and parameters on
which the models are based and how the models were constructed (Docket
No. W-98-26, Section III.G of the Rulemaking Record)) and SBF Economic
Analysis, Appendix A. EPA received no comments on this NODA with
respect to the economic methodology or the data.
The costs and revenues are compared yearly and the project is
assumed to run for 30 years or to shut in when operating costs exceed
revenues. That is, the economic models have differing lifetimes
according to project characteristics and each model may have a
shortened lifetime as a result of incremental costs. The model then
calculates the lifetime of the project, total production, and the net
present value of the operation (net income of the operation over the
life of the project in terms of today's dollars), which includes the
net operating earnings, taxes, expenditures on drilling, other capital
expenditures, etc. A positive net present value means that the project
is a good investment. In these cases, the return is greater than the
discount rate,
[[Page 6884]]
which represents the opportunity cost of capital. If the net present
value is negative, it means that money would have been better invested
elsewhere. For existing projects, the model uses current operations;
all expenditures in prior years, such as exploration, delineation, and
infrastructure development costs are considered sunk costs and are not
addressed. For new projects, the model uses data and parameters about
timing of the various phases of exploration, delineation and
development, along with cost estimates about costs incurred during
these phases to compute a full lifetime financial model of these
projects.
Each model is run twice--with and without the change due to
pollution control. The models support changes in both directions--i.e.,
costs or savings. If a model shows the net present value of a project
to be positive in the baseline, but would have a negative net present
value under any of the regulatory options, some or all of the wells
would not be drilled. This difference between baseline and
postcompliance would generate production impacts.
The likely outcome of today's rule is an overall savings associated
with the ability to discharge SBF cuttings (see Section VI.A). The cost
model (which provides the input to the economic models) projects that
the savings exceed any incremental costs of compliance in the
aggregate. EPA does not expect the alternate higher ROC limitation and
standard for drilling fluids with the stock base fluid performance of
esters to affect costs. EPA expects that operators will likely use
ester-based SBFs for the increased flexibility and not for any economic
benefits. The results of the economic models indicate no adverse
impacts on drilling well costs (exploratory or developmental), project
lifetime, or production for both BAT and NSPS projects. There are no
adverse impacts on firms, employment, trade, or inflation.
B. Small Business Analysis
Although today's rule will not have a significant economic impact
on a substantial number of small entities (see Section VII.A), EPA
assessed the impacts of the rule on small businesses. The small
business analysis is described more fully in Chapter 6 of the SBF
Economic Analysis.
The small business definitions and the methodology were outlined in
the April 2000 NODA and the February 1999 Proposal Economic Analysis
and have not changed. Briefly, EPA relied on the Small Business
Administration's size standards to determine whether a firm is a small
business. If EPA could not find employment or revenue data to confirm a
firm's size, it was classified as ``potentially'' small. EPA identified
40 small and potentially small firms. As noted in the previous
paragraph, today's rule results in cost savings, and EPA projects no
adverse impacts on small businesses.
VIII. Water Quality and Non-Water Quality Environmental Impacts of
Final Regulation
A. Overview of Water Quality and Non-Water Quality Environmental
Impacts
EPA conducted various analyses to assess the impact of the final
regulation on water quality, sediment quality, and human health. In
general, EPA has found that no adverse impacts are expected from
controlled discharges of SBFs.
B. Water Quality Modeling
In order to assess the impacts of potential SBF discharges to the
receiving waters, EPA conducted pore water, water column, and sediment
guidelines analyses. EPA calculated pollutant concentrations for both
the water column and pore water and compared them to the respective EPA
recommended marine water quality criteria or to applicable state
standards to determine the nature and magnitude of any projected water
quality exceedances. Details of the analyses and results are presented
in the final SBF Environmental Assessment.
EPA included the discharge of WBFs in the engineering analyses (see
Section II.A). Environmental impacts such as water column, pore water,
fish tissue and human health risk analyses were not estimated for the
discharge of WBFs versus the use and discharge of SBF cuttings.
However, industry has provided information that drilling is
significantly more efficient using SBFs rather than WBFs because hole
volumes with SBFs are approximately 1.8 times smaller. Therefore, the
pollutant loadings of appropriately controlled SBF discharge are less
than pollutant loadings associated with controlled WBF discharge.
1. Water Column Water Quality Analyses
There are no water quality criteria exceedances in the water column
for any of the regulatory options being considered including the ROC
option based on data from all four cuttings dryer technologies for
drilling fluids with the sediment toxicity and biodegradation
characteristics of ester-based SBFs which results in a slightly higher
LTA. Also, no Alaska state water quality standards are exceeded under
the discharge options in Cook Inlet, Alaska.
2. Pore Water Quality Analyses
As described above in Section III.D.1, the addition of several
seabed survey data changed the estimated SBF sediment concentration at
100 meters (328 feet) as used in the pore water quality analyses. The
revised analyses estimate that baseline (or BPT) pore water pollutant
concentrations at 100 meters from the discharge exceed recommended
water quality criteria for the heavy metal, chromium, for two model
well types, shallow water exploratory and deep water exploratory. There
are no pore water exceedances of any of the Alaska state water quality
standards for potential Cook Inlet, Alaska discharges. Also, there are
no pore water exceedances under the controlled SBF discharges (i.e.,
BAT/NSPS Options 1 and 2) including the ROC option based on data from
all four cuttings dryer technologies for drilling fluids with the
sediment toxicity and biodegradation characteristics of ester-based
SBFs which results in a slightly higher LTA.
3. Sediment Guidelines Analyses
The EPA proposed sediment guidelines for the protection of benthic
organisms assesses potential benthic impacts of certain metals. The
revised analyses, based on revised pore water concentrations, result in
2 exceedances only under the baseline (or BPT) conditions. There are no
sediment guidelines exceedances under controlled SBF discharge
conditions (i.e., BAT/NSPS Options 1 and 2) including the ROC option
based on data from all four cuttings dryer technologies for drilling
fluids with the sediment toxicity and biodegradation characteristics of
ester-based SBFs which results in a slightly higher LTA.
C. Human Health Effects Modeling
The human health risk analyses were revised to incorporate changes
to the fish consumption rates (see Section III.D.b). The revised
analyses show no risk to human health.
D. Seabed Surveys
EPA reviewed the seabed surveys submitted during public comment to
the April 2000 NODA. As previously stated, EPA used data from two
surveys drilling six wells with SBFs in the environmental assessment
analyses. Additionally, EPA also received information on the on-going
joint Industry/MMS GOM seabed survey. The Industry/MMS workgroup has
[[Page 6885]]
completed the first two cruises of the four cruise study (see Section
III.D.1). Outside of a 50-100' radius from the drilling facility, no
visible cuttings accumulations (large or small) were detected at any of
the drilling facility survey sites.
E. Energy Impacts
As described in Sections III.E and IV.E, EPA included additional
data and revised several parameters in estimating energy impacts of the
final SBF rule. EPA estimated the amount of fuel required, expressed as
barrels of oil equivalents per year (BOE/yr), to operate the equipment
associated with each of the regulatory options as well as the fuel
consumed by daily rig operations. EPA also estimated the current energy
requirements of WBF discharge in order to determine the relative
decrease in impacts of SBF versus WBF use. EPA does not expect the
alternate higher ROC limitation and standard for drilling fluids with
the stock base fluid performance of esters to affect energy impacts
because equipment used under the ester option (e.g., shale shakers,
cuttings dryer, fines removal unit) has the same or similar energy
requirements. The results of the energy impact analysis are presented
in Tables 6 and 7 for existing and new sources, respectively.
Table 6.--Incremental Summary Annual Energy Impacts, Existing Sources
----------------------------------------------------------------------------------------------------------------
Energy impacts: Reductions (Increases)a fuel use (BOE/
yr)
Technology basis -------------------------------------------------------
Gulf of Offshore Cook Inlet,
Mexico California AK Total
----------------------------------------------------------------------------------------------------------------
BAT/NSPS Option 1: Discharge with LTA of 4.03% SBF ROC.. 202,146 0 19 202,165
BAT/NSPS Option 2: Discharge with LTA of 3.82% SBF ROC.. 195,124 0 0 195,124
BAT/NSPS Option 3: Zero Discharge of SBF-wastes via land (346,459) (6,138) (6,067) (358,664)
disposal or onsite injection...........................
----------------------------------------------------------------------------------------------------------------
a Annual fuel usage reductions or increases are incremental to baseline/current practice (i.e., discharge of SBF-
cuttings at 10.2% ROC in the GOM and zero discharge in Offshore California and Cook Inlet, AK).
Note: BOE = Barrels of Oil Equivalent.
Note: The following terms are used in this table: long-term average (LTA) and retention on cuttings (ROC).
Table 7.--Incremental Summary Annual Energy Impacts, New Sources
------------------------------------------------------------------------
Energy impacts:
Technology basis Reductions (increases)a
fuel use (BOE/yr)
------------------------------------------------------------------------
BAT/NSPS Option 1: Discharge with LTA of 4.03% 6330
SBF ROC......................................
BAT/NSPS Option 2: Discharge with LTA of 3.82% 5693
SBF ROC......................................
BAT/NSPS Option 3: Zero Discharge of SBF- (18,067)
wastes via land disposal or onsite injection.
------------------------------------------------------------------------
a Annual fuel usage reductions or increases are incremental to baseline/
current practice (i.e., discharge of SBF-currings at 10.2% ROC in the
GOM).
Note: BOE = Barrels of Oil Equivalent.
Note: The following terms are used in this table: long-term average
(LTA) and retention on cuttings (ROC).
Note: EPA estimates no new sources for Offshore California or Cook
Inlet, AK.
F. Air Emission Impacts
EPA calculated the air emissions, expressed as short tons per year,
resulting from activities associated with each of the regulatory
options. Air emissions are a function of the: (1) Type of fuel burned
(e.g., natural gas or diesel); and (2) amount of fuel consumed as
determined from the length of equipment operation and the fuel
consumption rate. The methodology and modeling parameters parallel that
of the energy impact analysis as the amount of fuel consumed is the
basis for the air emissions analysis. Therefore, the air emissions
analysis includes the estimate of emissions of daily rig operations and
an estimate of WBF drilling operation air emissions. EPA does not
expect the alternate higher ROC limitation and standard for drilling
fluids with the stock base fluid performance of esters to affect air
emissions because equipment used under the ester option (e.g., shale
shakers, cuttings dryer, fines removal unit) has the same or similar
air emissions. The results of the air emission analysis are presented
in Tables 8 and 9 for existing and new sources, respectively.
Table 8.--Incremental Summary Annual Air Emissions, Existing Sources
----------------------------------------------------------------------------------------------------------------
Annual Air Emission Reductions (Increases) a (tons/yr)
-------------------------------------------------------
Technology basis Gulf of Offshore Cook Inlet,
Mexico California AK Total
----------------------------------------------------------------------------------------------------------------
BAT/NSPS Option 1: Discharge with LTA of 4.03% SBF ROC.. 3,172 0 0 3,172
BAT/NSPS Option 2: Discharge with LTA of 3.82% SBF ROC.. 3,074 0 (1) 3,073
BAT/NSPS Option 3: Zero Discharge of SBF-wastes via land (5,414) (94) (94) (5,602)
disposal or onsite injection...........................
----------------------------------------------------------------------------------------------------------------
a Annual air emissions reductions or increases are incremental to baseline/current practice (i.e., discharge of
SBF-cuttings at 10.2% ROC in the GOM and zero discharge in Offshore California and Cook Inlet, AK).
Note: 1 ton = 2000 lbs.
Note: The following terms are used in this table: long-term average (LTA) and retention cuttings (ROC).
[[Page 6886]]
Table 9.--Incremental Summary Air Emissions, New Sources--Gulf of Mexico
------------------------------------------------------------------------
Annual air
emissions
Technology basis reduction
(increases)
a (tons/yr)
------------------------------------------------------------------------
BAT/NSPS Option 1: Discharge with LTA of 4.03% SBF ROC.... (136)
BAT/NSPS Option 2: Discharge with LTA of 3.82% SBF ROC.... (145)
BAT/NSPS Option 3: Zero Discharge of SBF-wastes via land (528)
disposal or onsite injection.............................
------------------------------------------------------------------------
a Annual air emissions reductions or increases are incremental to
baseline/current practice (i.e., discharge of SBF-cuttings at 10.2%
ROC in the GOM).
Note: 1 ton = 2000 lbs.
Note: The following terms are used in this table: long-term average
(LTA) and retention on cuttings (ROC).
Note: EPA estimates no new sources for Offshore California or Cook
Inlet, AK.
G. Air Emissions Monetized Human Health Benefits
EPA estimated emissions associated with each of the regulatory
options as part of the NWQI analyses. The pollutants considered in the
NWQI analyses are nitrogen oxides ( NOX), volatile organic
carbon (VOC), particulate matter (PM), sulfur dioxide (SO2),
and carbon monoxide (CO). Of these pollutants, EPA monetized the human
health benefits or impacts associated with VOC, PM, and SO2
emissions using the methodology presented in the Environmental
Assessment of the Final Effluent Limitations Guidelines and Standards
for the Pharmaceutical Manufacturing Industry (EPA-821-B-98-008). Each
of these pollutants have human health impacts and reducing these
emissions can reduce these impacts.
Several VOCs exhibit carcinogenic and systemic effects and VOCs, in
general, are precursors to ground-level ozone, which negatively affects
human health and the environment. PM impacts include aggravation of
respiratory and cardiovascular disease and altered respiratory tract
defense mechanisms. SO2 impacts include nasal irritation and
breathing difficulties in humans and acid deposition in aquatic and
terrestrial ecosystems.
The unit values (in 1990 dollars) are $489 to $2,212 per megagram
(Mg) of VOC; $10,823 per Mg of PM; and $3,516 to $4,194 per Mg of
SO2. Using the Engineering News Record Construction Cost
Index (see www.enr.com/cost/costcci.asp) these conversion factors are
scaled up using the ratio of 6060:4732 (1999$:1990$). EPA does not
expect the alternate higher ROC limitation and standard for drilling
fluids with the stock base fluid performance of esters to affect
monetized benefits because equipment used under the ester option (e.g.,
shale shakers, cuttings dryer, fines removal unit) has the same or
similar air emissions. Following is a summary of the monetized benefits
for each of the regulatory options for both existing and new sources.
BILLING CODE 6560-50-U
[[Page 6887]]
[GRAPHIC] [TIFF OMITTED] TR22JA01.159
[[Page 6888]]
[GRAPHIC] [TIFF OMITTED] TR22JA01.160
H. Solid Waste Impacts
EPA calculated the amount of waste cuttings that would be land
disposed, injected onshore, and/or injected onsite in each regulatory
scenario, and determined that there would be a considerable reduction
in the amount of drill cuttings land disposed and injected with the
implementation of a controlled discharge option for SBF-cuttings.
EPA's analyses show that under the SBF-cuttings zero discharge
option as compared to current practice, for U.S. Offshore waters
existing sources, there would be an annual increase of 35 million
pounds of cuttings shipped to shore for disposal in non-hazardous
oilfield waste (NOW) sites and an increase of 166 million pounds of
cuttings injected. In addition, under the SBF-cuttings zero discharge
option, operators would use the more toxic OBFs. The zero discharge
option for SBF-cuttings would lead to an increase in annual fuel usage
of 358,664 BOE and an increase in annual air emissions of 5,602 tons.
Finally, the SBF-cuttings zero discharge option in the U.S. Offshore
waters would lead to an increase of 51 million pounds of WBF cuttings
being discharged to U.S. Offshore waters. This pollutant loading
increase is a result of GOM operators switching from efficient SBF
drilling to less efficient WBF drilling.
Additionally, EPA's analyses show that under the SBF-cuttings zero
discharge option as compared to current practice, for GOM new sources,
there would be an annual increase of 3.4 million pounds of drill
cuttings shipped to shore for disposal in NOW sites and an increase of
10.2 million pounds of drill cuttings injected. These zero discharge
options for SBF-cuttings would lead to an increase in annual fuel use
of 18,067 BOE and an increase in annual air emissions of 528 tons.
Finally, the SBF-cuttings zero discharge option in the GOM would lead
to an increase of 7.5 million pounds of WBF-cuttings being discharged
to U.S. Offshore waters. Again, this pollutant loading increase is a
result of GOM operators switching from efficient SBF drilling to less
efficient WBF drilling.
I. Other Factors
EPA also considered the impact of the effluent limitations
guidelines and
[[Page 6889]]
standards on safety. EPA has identified two safety issues related to
drilling fluids: (1) Deleterious vapors generated by organic materials
in drilling fluids; and (2) waste hauling activities that increase the
risk of injury to workers.
1. Vapors Generated by Organic Materials in Drilling Fluids
One of the key concerns in exploration and production projects is
the exposure of wellsite personnel to vapors generated by organic
materials in drilling fluids (Docket No. W-98-26, Record No. III.D.12).
Areas on the drilling location with the highest exposure potentials are
sites near solids control and open pits. These areas are often enclosed
in rooms and ventilated to prevent unhealthy levels of vapors from
accumulating. If the total volume of organic vapors can be reduced then
any potential health effects will also be reduced regardless of the
nature of the vapors.
Generally speaking the aromatic fraction of the vapors is the most
toxic to the mammalian system. The high volatility and absorbability
through the lungs combined with their high lipid solubility serve to
increase their toxicity. OBFs have a high aromatic content and vapors
generated from using these drilling fluids include aromatics (e.g.,
alkybenzenes, naphthalenes, and alkyl-naphthalenes), alkanes (e.g., C
7 -C 18 straight chained and branched), and
alkenes. Some minerals oils also generate vapors that contain the same
types of chemical compounds, but generally at lower concentrations, as
those found in the diesel vapors (e.g., aromatics, alkanes, cyclic
alkanes, and alkenes). Because SBF are manufactured from compounds with
specifically defined compositions, the subsequent compound can exclude
toxic aromatics. Consequently, toxic aromatics can be excluded from the
vapors generated by using SBFs.
In general, SBFs (e.g., esters, LAOs, PAOs, IOs) generate much
lower concentrations of vapors than do OBFs (Docket No. W-98-26, Record
No. III.D.12). Moreover, the vapors generated by these SBFs are less
toxic than traditional OBFs because they do not contain aromatics.
2. Waste Hauling Activities
Industry has commented in previous effluent guidelines, such as the
Coastal Subcategory Oil and Gas Extraction and Development ELG, that a
zero discharge requirement would increase the risk of injury to workers
due to increased waste hauling activities. These activities include
vessel trips to and from the drilling facility to haul waste, transfer
of waste from the drilling facility onto a service vessel, and transfer
in port onto a barge or dock.
EPA has identified and reviewed additional data sources to
determine the likelihood that imposition of a zero discharge limitation
on cuttings contaminated with SBF could increase risk of injury due to
additional waste hauling demands. The sources of safety data are the
U.S. Coast Guard (USCG), the Minerals Management Service (MMS), the
American Petroleum Institute (API), and the Offshore Marine Service
Association (OMSA). The following is a summary of the findings from
this review.
The data indicate that there are reported incidents that are
associated with the collection, hauling, and onshore disposal of wastes
from offshore. However, the data do not distinguish whether any of
these incidents can be attributed to specific waste management
activities.
Most offshore incidents are due to human error or equipment
failure. The rate at which these incidents occur will not be changed
significantly by increased waste management activities. However, if the
number of man hours and/or equipment hours are increased, there will be
more reportable incidents given an unchanged incident rate. These
potential increases may be offset by reduced incident rates through
increased training or equipment maintenance and inspection; but these
changes cannot be predicted. One indication that training and
maintenance can reduce incident rates is a 1998 API report entitled
``1997 Summary of U.S. Occupational Injuries, Illnesses, and Fatalities
in the Petroleum Industry,'' which established that injury incident
rates have been decreasing over the last 14 years. If this decrease
continues, there should be no increase in the number of safety
incidents due to a requirement to haul SBF-contaminated cuttings to
shore for disposal. The details of this analysis are available in a
technical support document in the rule record for today's final rule.
IX. Regulatory Requirements
A. Executive Order 12866: Regulatory Planning and Review
Under Executive Order 12866 (58 FR 51735 (October 4, 1993)), the
Agency 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 recommendations are documented in the
public record.
B. Regulatory Flexibility Act (RFA), as amended by the Small Business
Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 USC 601 et.
seq.
The RFA generally requires an agency to prepare a regulatory
flexibility analysis of any rule subject to notice and comment rule
requirements under the Administrative Procedure Act or any other
statute unless the agency certifies that the rule will not have a
significant economic impact on a substantial number of small entities.
Small entities include small businesses, small organizations, and small
governmental jurisdictions.
For purposes of assessing the impacts of today's rule on small
entities, small entity is defined as: (1) A small business with fewer
than 500 employees for oil and gas production operators and less than
$5 million per year in revenues for oil and gas services providers
(i.e., the definitions from SBA's size standards); (2) a small
governmental jurisdiction that is a government of a city, county, town,
school district, or special district with a population of less than
50,000; and (3) a small organization that is any not-for-profit
enterprise which is independently owned and operated and is not
dominant in its field. After considering the economic impact of today's
final rule on small entities, I certify that this action will not have
a significant economic impact on a substantial number of small
entities. Today's rule affects small businesses only; there are no
impacts on small governmental jurisdictions or small organizations.
[[Page 6890]]
In determining whether a rule has a significant economic impact on
a substantial number of small entities, the impact of concern is any
significant adverse economic impact on small entities. Since the
primary purpose of the regulatory flexibility analysis is to identify
and address regulatory alternatives ``which minimizes any significant
economic impact of the proposed rule on small entities.'' 5 U.S.C.
Sections 603 and 604. Thus, an agency may certify that a rule will not
have a significant economic impact on a substantial number of small
entities if the rule relieves regulatory burden, or otherwise has a
positive economic effect on all of the small entities subject to the
rule.
EPA projects that today's rule will result in operational savings
and will have no adverse economic impacts. These conclusions apply to
all firms, both large and small. EPA estimates that between five and 40
small businesses (between five and 40% of all firms) are covered by
today's rule. If the small businesses are using SBF and continue to do
so, or if they switch to SBF, they need to comply with today's effluent
limitations. EPA estimates that the operational savings associated with
an allowable SBF-cuttings discharge will result in an economic
advantage, contrasted to other SBF-cuttings regulatory scenarios. EPA
selected the controlled discharge option which will allow operators to
use of SBF in place of OBF and WBFs. Using SBFs in place of OBFs will
generally shorten the length of the drilling project and eliminate the
need to barge to shore or re-inject OBF-waste cuttings, thereby
reducing costs and NWQI such as fuel use, air emissions, and land
disposal of OBFs. Use of SBFs in place of WBFs would also lead to: (1)
a decrease in costs and NWQIs due to the decreased length of the
drilling project; and (2) a per well decrease of pollutants discharged
due to improved technical performance of SBFs. EPA estimates that the
rule will result in annual savings of $48.9 million and no adverse
economic impacts to the industry as a whole. Further, after
considerable study, EPA's record indicates that there will be no
significant economic impacts to any small entity subject to the rule.
The SBF Economic Analysis describes these results in more detail. We
have therefore conducted that today's final rule will relieve
regulatory burden for all small entities.
C. Submission to Congress and the General Accounting Office
The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
United States. EPA will submit a report containing this rule and other
required information to the U.S. Senate, the U.S. House of
Representatives, and the Comptroller General of the United States prior
to publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is not a ``major rule'' as defined by 5 U.S.C.
804(2). This rule will be effective February 21, 2001.
D. Paperwork Reduction Act
The Office of Management and Budget (OMB) has approved the
information collection requirements contained in this rule under the
provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and
has assigned OMB control number 2040-0230.
The information collection requirements are related to the optional
use of Best Management Practices (BMPs) in order to reduce SBF-cuttings
monitoring. Operators that elect to not use the BMP alternative are not
subject to the information collection requirements in today's final
rule. BMPs are inherently pollution prevention practices. BMPs may
include the universe of pollution prevention encompassing production
modifications, operational changes, material substitution, materials
and water conservation, and other such measures. BMPs include methods
to prevent toxic and hazardous pollutants from reaching receiving
waters. Because BMPs are most effective when organized into a
comprehensive facility BMP Plan, EPA is requiring operators to complete
a BMP Plan when they select the BMP alternative.
The BMP alternative requires operators to develop and, when
appropriate, amend plans specifying how operators will implement the
specified BMP alternative, and to certify to the permitting authority
that they have done so in accordance with good engineering practices
and the requirements of the regulation. The purpose of those provisions
is, respectively, to facilitate the implementation of BMP alternative
on a site-specific basis and to help the regulating authorities to
ensure compliance without requiring the submission of actual BMP Plans.
Finally, the recordkeeping provisions are intended to facilitate
training, to signal the need for different or more vigorously
implemented BMPs, and to facilitate compliance assessment.
The information collection requirements in the final rule include,
for example: (1) Training personnel; (2) analyzing spills that occur;
(3) identifying equipment items that might need to be maintained,
upgraded, or repaired; (4) identifying procedures for waste
minimization; (5) performing monitoring (including the operation of
monitoring systems) to establish equivalence with a numeric cuttings
retention limitation and to detect leaks, spills, and intentional
diversion; and (6) generally to periodically evaluate the effectiveness
of the BMP alternatives.
EPA does not expect that any confidential business information or
trade secrets will be required from oil and gas extraction operators as
part of this ICR. If information submitted in conjunction with this ICR
were to contain confidential business information, the respondent has
the authority to request that the information be treated as
confidential business information. All data so designated will be
handled by EPA pursuant to 40 CFR part 2. This information will be
maintained according to procedures outlined in EPA's Security Manual
Part III, Chapter 9, dated August 9, 1976. Pursuant to section 308(b)
of the CWA, effluent data may not be treated as confidential.
EPA estimated the burden and costs to the regulated community
(approximately 67 SBF well drilling facilities annually) and EPA, the
NPDES permit control authority, for data collection and record keeping
associated with implementation of the BMP alternative. EPA estimates
the public reporting burden for the selected BMP option as 787 hours
per respondent per year (i.e., (16,750 initial hours/3 years + 47,168
annual hours/year)/67 SBF well operators). EPA also estimated the
annual burden for EPA Regions, the NPDES permit controlling
authorities, to review BMPs and ensure compliance. EPA estimates that
essentially all of the SBF discharges will occur in Federal offshore
waters or in Cook Inlet, Alaska, where EPA Region X retains NPDES
permit controlling authority. The EPA Regional burden for reviewing BMP
Plans is estimated at 380 hours per year (i.e., (536 initial hours/3
years + 201 annual hours/year)).
EPA estimates the public reporting costs as $24,058 per respondent
per year (i.e., ($1,235,313 initial costs/3 years + $1,200,138 annual
costs/year)/67 SBF well operators). The EPA Regional costs for
reviewing BMP Plans is estimated at approximately $12,149 per year
(i.e.,
[[Page 6891]]
($17,152 initial costs/3 years + $6,432 annual costs/year)).
Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a Federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of information;
and transmit or otherwise disclose the information.
An Agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations are listed in 40 CFR part 9 and 48 CFR chapter 15. EPA is
amending the table in 40 CFR part 9 of currently approved ICR control
numbers issued by OMB for various regulations to list the information
requirements contained in this final rule.
E. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures to State, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million or more in any
one year. Before promulgating an EPA rule for which a written statement
is needed, section 205 of the UMRA generally requires EPA to identify
and consider a reasonable number of regulatory alternatives and adopt
the least costly, most cost-effective or least burdensome alternative
that achieves the objectives of the rule. The provisions of section 205
do not apply when they are inconsistent with applicable law. Moreover,
section 205 allows EPA to adopt an alternative other than the least
costly, most cost-effective or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted. Before EPA establishes any regulatory
requirements that may significantly or uniquely affect small
governments, including tribal governments, it must have developed under
section 203 of the UMRA a small government agency plan. The plan must
provide for notifying potentially affected small governments, enabling
officials of affected small governments to have meaningful and timely
input in the development of EPA regulatory proposals with significant
Federal intergovernmental mandates, and informing, educating, and
advising small governments on compliance with the regulatory
requirements.
EPA has determined that this rule does not contain a Federal
mandate that may result in expenditures of $100 million or more for
State, local, and tribal governments, in the aggregate, or the private
sector in any one year. EPA projects that the effect of the rule will
be a operational savings. EPA has estimated this savings at $48.9
million (1999$, post-tax). Thus, today's rule is not subject to the
requirements of Sections 202 and 205 of the UMRA.
EPA has determined that this rule contains no regulatory
requirements that might significantly or uniquely affect small
governments. EPA projects that no small governments will be affected by
this rule as small governments are not engaged in oil and gas
extraction operations in offshore and coastal waters or in issuing
NPDES permits for oil and gas extraction operations in offshore and
coastal waters. Thus, today's rule is not subject to the requirements
of section 203 of the UMRA.
F. Executive Order 13084: Consultation and Coordination With Indian
Tribal Governments
Under Executive Order 13084 EPA may not issue a regulation that is
not required by statute, that significantly or uniquely affects the
communities of Indian Tribal governments, and that imposes substantial
direct compliance costs on those communities, unless the Federal
government provides the funds necessary to pay the direct compliance
costs incurred by the tribal governments, or EPA consults with those
governments. If EPA complies by consulting, Executive Order 13084
requires EPA to provide to the Office of Management and Budget, in a
separately identified section of the preamble to the rule, a
description of the extent of EPA's prior consultation with
representatives of affected tribal governments, a summary of the nature
of their concerns, and a statement supporting the need to issue the
regulation. In addition, Executive Order 13084 requires EPA to develop
an effective process permitting elected officials and other
representatives of Indian tribal governments ``to provide meaningful
and timely input in the development of regulatory policies on matters
that significantly or uniquely affect their communities.''
Today's rule does not significantly or uniquely affect the
communities of Indian tribal governments nor does it impose substantial
direct compliance costs on them. EPA has determined that currently, no
communities of Indian tribal governments are affected by this rule as
Indian tribal governments are not engaged in oil and gas extraction
operations in offshore and coastal waters or in issuing NPDES permits
for oil and gas extraction operations in offshore and coastal waters.
Accordingly, the requirements of section 3(b) of Executive Order 13084
do not apply to this rule.
G. Executive Order 13132: Federalism
Executive Order 13132, entitled ``Federalism'' (64 FR 43255, August
10, 1999), requires EPA to develop an accountable process to ensure
``meaningful and timely input by State and local officials in the
development of regulatory policies that have federalism implications.''
``Policies that have federalism implications'' is defined in the
Executive Order to include regulations that have ``substantial direct
effects on the States, on the relationship between the national
government and the States, or on the distribution of power and
responsibilities among the various levels of government.''
This final rule does not have federalism implications. It will not
have substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government,
as specified in Executive Order 13132. The rule establishes effluent
limitations and standards imposing requirements that apply to oil and
gas extraction operations in offshore and coastal waters. EPA has
determined that there are no oil and gas extraction operations in
offshore and coastal waters that are owned and operated by State or
local governments. Therefore, this rule will not impose any
requirements on State or local governments. Further, the rule will not
affect State governments' authority to implement CWA and UIC permitting
programs. In fact, the final rule may reduce administrative costs on
States that have authorized NPDES programs because although these
States must incorporate the new limitations and
[[Page 6892]]
standards in new and revised NPDES permits, they no longer will need to
make Best Professional Judgement (BPJ) determinations regarding the
appropriate level of technology control. We recognize that there may be
a small administrative cost to the State of Alaska to assist EPA Region
10 in determining whether Coastal Cook Inlet, Alaska, operators qualify
for the SBF-cuttings zero discharge exemption (see Section V.F). Thus,
Executive Order 13132 does not apply to this rule.
H. National Technology Transfer and Advancement Act
As noted in the proposed rule (64 FR 5528), section 12(d) of the
National Technology Transfer and Advancement Act (NTTAA) of 1995, Pub
L. 104-113 section 12(d) (15 U.S.C. 272 note), directs EPA to use
voluntary consensus standards in its regulatory activities unless to do
so would be inconsistent with applicable law or otherwise impractical.
Voluntary consensus standards are technical standards (e.g., materials
specifications, test methods, sampling procedures, and business
practices) that are developed or adopted by voluntary consensus
standard bodies. The NTTAA directs EPA to provide Congress, through the
Office of Management and Budget (OMB), explanations when the Agency
decides not to use available and applicable voluntary consensus
standards.
This rule involves technical standards. The rule requires
dischargers to measure for two metals, PAH content (as phenanthrene),
sediment toxicity, aqueous toxicity, biodegradation rate, formation oil
content, and base fluid retained on cuttings. EPA performed a search to
identify potentially applicable voluntary consensus standards that
could be used to measure the parameters in today's rule. EPA did locate
several voluntary consensus standards that required modification for
inclusion in the final rule. EPA considered public comments on the
proposed rule and worked with stakeholders, including the industry
sponsored Synthetic Based Muds Research Consortium (SBMRC), to modify
or develop new standards for various parameters (i.e., sediment
toxicity, biodegradation rate, PAH content (as phenanthrene), formation
oil content, base fluid retained on cuttings). EPA has decided to use
modified versions of the following voluntary consensus standards: (1)
EPA Method 1654A; (2) ASTM E-1367-92; (3) ISO 11734:1995; and (4) API
Recommended Practice 13B-2. As indicated by industry comments on the
February 1999 proposal and April 2000 NODA, industry stakeholders
support the use of these modified voluntary consensus standards (see
Docket No. W-98-26, Record No. IV.A.a.13).
I. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
The Executive Order 13045, ``Protection of Children from
Environmental Health Risks and Safety Risks'' (62 FR 19885, April 23,
1997), applies to any rule that: (1) Is determined to be ``economically
significant'' as defined under Executive Order 12866, and (2) concerns
an environmental health or safety risk that EPA has reason to believe
may have a disproportionate effect on children. If the regulatory
action meets both criteria, the Agency must evaluate the environmental
health or safety effects of the planned rule on children and explain
why the planned regulation is preferable to other potentially effective
and reasonably feasible alternatives considered by the Agency. This
final rule is not subject to E.O. 13045 because it is not
``economically significant'' as defined under Executive Order 12866,
and because the rule does not concern an environmental health or safety
risk that may have a disproportionate effect on children.
J. Executive Order 13158: Marine Protected Areas
Executive Order 13158 (65 FR 34909, May 31, 2000) requires EPA to
``expeditiously propose new science-based regulations, as necessary, to
ensure appropriate levels of protection for the marine environment.''
EPA may take action to enhance or expand protection of existing marine
protected areas and to establish or recommend, as appropriate, new
marine protected areas. The purpose of the executive order is to
protect the significant natural and cultural resources within the
marine environment, which means ``those areas of coastal and ocean
waters, the Great Lakes and their connecting waters, and submerged
lands thereunder, over which the United States exercises jurisdiction,
consistent with international law.''
EPA believes that this final rule is consistent with the objectives
of the Executive Order to protect the ocean environment. By encouraging
the use of appropriately controlled SBFs in the place of more toxic
OBFs, the ocean will be protected from the effects of spills of OBFs
and from the effects of disposal of OBFs onshore. By encouraging the
use of appropriately controlled SBFs over WBFs, there will much less
drilling waste generated and discharged to the ocean per well and the
drilling waste discharged will be far less toxic and will biodegrade at
a much faster rate than those of traditional drilling fluids.
X. Regulatory Implementation
Upon promulgation of these regulations, the effluent limitations
for the appropriate subcategory must be applied in all Federal and
State NPDES permits issued to affected direct dischargers in the oil
and gas extraction industry. This section discusses the relationship of
upset and bypass provisions, variances and modifications, and
monitoring requirements.
A. Implementation of Limitations and Standards
Upon the promulgation of these regulations, all new and reissued
Federal and State NPDES permits issued to direct dischargers in the oil
and gas extraction industry must include the effluent limitations for
the appropriate subcategory. Permit writers should be aware that EPA
has now finalized revisions to 40 CFR 122.44(a) which could be
particularly relevant to the development of NPDES permits for the oil
and gas extraction point source category (see 65 FR 30989, May 15,
2000). As finalized, the revision would require that permits have
limitations for all applicable guidelines-listed pollutants but allows
for the waiver of sampling requirements for guideline-listed pollutants
on a case-by-case basis if the discharger can certify that the
pollutant is not present in the discharge or present in only background
levels from intake water with no increase due to the activities of the
dischargers. New sources and new dischargers are not eligible for this
waiver for their first permit term, and monitoring can be re-
established through a minor modification if the discharger expands or
changes its process. Further, the permittee must notify the permit
writer of any modifications that have taken place over the course of
the permit term and, if necessary, monitoring can be reestablished
through a minor modification.
B. Upset and Bypass Provisions
A ``bypass'' is an intentional diversion of waste streams from any
portion of a treatment facility. An ``upset'' is an exceptional
incident in which there is unintentional and temporary noncompliance
with technology-based permit effluent limitations because of factors
beyond the reasonable control of the permittee. EPA's regulations
concerning bypasses and upsets are set forth at 40 CFR 122.41(m) and
(n), and 40 CFR 403.16 (upset) and 403.17
[[Page 6893]]
(bypass). The reader is also referred to the Offshore Guidelines (58 FR
12501) for a discussion on upset and bypass provisions.
C. Variances and Modifications
The CWA requires application of the effluent limitations and
standards established pursuant to section 301, 304, 306, or the
pretreatment standards of section 307 to all direct and indirect
dischargers. However, section 301(n) provides for the modification of
these national requirements in a limited number of circumstances.
Moreover, the Agency has established administrative mechanisms to
provide an opportunity for relief from the application of national
effluent limitations guidelines and pretreatment standards for
categories of existing sources for priority, conventional and non-
conventional pollutants (e.g., fundamentally different factor
variances, removal credits).
The Fundamentally Different Factors (FDF) variances considers those
facility specific factors which a permittee may consider to be uniquely
different from those considered in the formulation of an effluent
limitations guidelines as to make the limitation inapplicable. An FDF
variance must be based only on information submitted to EPA during the
rulemaking establishing the effluent limitations guidelines from which
the variance is being requested, or on information the applicant did
not have a reasonable opportunity to submit during the rulemaking
process for these effluent limitations guidelines. FDF variance
requests must be received by the permitting authority within 180 days
of publication of the final rule. The specific regulations covering the
requirements for the administration of FDF variances are found at 40
CFR 122.21(m)(1), and 40 CFR part 125, subpart D.
D. Relationship of Effluent Limitations to NPDES Permits and Monitoring
Requirements
Effluent limitations act as a primary mechanism to control the
discharges of pollutants to waters of the United States. These
limitations are applied to individual facilities through NPDES permits
issued by EPA or authorized States under section 402 of the Act.
The Agency has developed the limitations for this regulation to
cover the discharge of pollutants for this industrial category. In
specific cases, the NPDES permitting authority may elect to establish
technology-based permit limits for pollutants not covered by this
regulation. In addition, if State water quality standards or other
provisions of State or Federal Law require limits on pollutants not
covered by this regulation (or require more stringent limits on covered
pollutants), the permitting authority must apply those limitations.
Working in conjunction with the effluent limitations are the
monitoring conditions set out in a NPDES permit. An integral part of
the monitoring conditions is the point at which a facility must monitor
to demonstrate compliance. The point at which a sample is collected can
have a dramatic effect on the monitoring results for that facility.
Therefore, it may be necessary to require internal monitoring points in
order to ensure compliance. Authority to address internal waste streams
is provided in 40 CFR 122.44(i)(1)(iii) and 122.45(h). Permit writers
may establish additional internal monitoring points to the extent
consistent with EPA's regulations.
An important component of the monitoring requirements established
by the permitting authority is the frequency at which monitoring is
required. In costing the various technology options for the oil and gas
extraction industry, EPA assumed yearly SBF stock limitations
monitoring for mercury, cadmium, PAH (as phenanthrene), sediment
toxicity, and biodegradation rates and daily or monthly monitoring for
diesel oil contamination, formation oil contamination, base fluid
retained on cuttings, aqueous toxicity, and sediment toxicity. These
monitoring frequencies may be lower than those generally imposed by
some permitting authorities, but EPA believes these reduced frequencies
are appropriate due to the relative costs of monitoring when compared
to the estimated costs of complying with the promulgated limitations.
E. Analytical Methods
Section 304(h) of the Clean Water Act directs EPA to promulgate
guidelines establishing test procedures for the analysis of pollutants.
These test procedures (methods) are used to determine the presence and
concentration of pollutants in wastewater, and are used for compliance
monitoring and for filing applications for the NPDES program under 40
CFR 122.21, 122.41, 122.44 and 123.25, and for the implementation of
the pretreatment standards under 40 CFR 403.10 and 403.12. To date, EPA
has promulgated methods for conventional pollutants, toxic pollutants,
and for some non-conventional pollutants. The five conventional
pollutants are defined at 40 CFR 401.16. Table I-B at 40 CFR part 136
lists the analytical methods approved for these pollutants. The 65
toxic metals and organic pollutants and classes of pollutants are
defined at 40 CFR 401.15. From the list of 65 classes of toxic
pollutants EPA identified a list of 126 ``Priority Pollutants.'' This
list of Priority Pollutants is shown, for example, at 40 CFR part 423,
Appendix A. The list includes non-pesticide organic pollutants, metal
pollutants, cyanide, asbestos, and pesticide pollutants.
Currently approved methods for metals and cyanide are included in
the table of approved inorganic test procedures at 40 CFR 136.3, Table
I-B. Table I-C at 40 CFR 136.3 lists approved methods for measurement
of non-pesticide organic pollutants, and Table I-D lists approved
methods for the toxic pesticide pollutants and for other pesticide
pollutants. Dischargers must use the test methods promulgated at 40 CFR
136.3 or incorporated by reference in the tables, when available, to
monitor pollutant discharges from the oil and gas industry, unless
specified otherwise in part 435 or by the permitting authority.
As part this rule, EPA is promulgating the use of analytical
methods for determining additional parameters that are specific to
characterizing SBFs and other drilling fluids which do not disperse in
water. These additional stock base fluid parameters include PAH content
(as phenanthrene), sediment toxicity, and biodegradation rate.
Additional discharge limitations include prohibition of diesel oil
discharge, formation (crude) oil contamination, aqueous phase toxicity,
sediment toxicity, and quantity of drilling fluid discharged with
cuttings.
EPA worked with stakeholders to identify methods for determining
these parameters. For PAH content (as phenanthrene), EPA is
promulgating the use of EPA Method 1654A. For biodegradation rate, EPA
is promulgating the use of the anaerobic closed bottle biodegradation
test (i.e., ISO 11734:1995) as modified for the marine environment
(i.e., Appendix 4 of subpart A of 40 CFR part 435). For base fluid
sediment toxicity, EPA is promulgating the use of the American Society
for Testing and Material (ASTM) Method E-1367-92 supplemented with
sediment preparation procedures (i.e., Appendix 3 of subpart A of 40
CFR part 435). For drilling fluid sediment toxicity, EPA is
promulgating the use of ASTM Method E-1367-92 supplemented with
sediment preparation procedures (i.e., Appendix 3 of subpart A of 40
CFR part 435) and reference drilling fluid preparation procedures
(i.e., Appendix 8 of subpart
[[Page 6894]]
A of 40 CFR part 435). For aqueous toxicity, EPA is promulgating the
use of the Suspended Particulate Phase (SPP) toxicity test (Appendix 2
of subpart A of 40 CFR part 435). For formation (crude) oil
contamination in drilling fluid, EPA is promulgating the use of two
methods: a reverse phase extraction fluorescence test (RPE) and a gas
chromatography/mass spectrometry (GC/MS) test. The RPE test (i.e.,
Appendix 6 of subpart A of 40 CFR part 435) is a screening method that
provides a quick and inexpensive determination of oil contamination for
use on offshore well drilling sites, while the GC/MS test (i.e.,
Appendix 5 of subpart A of 40 CFR part 435) provides: (1) A definitive
identification and quantification of oil contamination for baseline
analysis; and (2) confirmatory results for the RPE when the RPE results
need confirmation. For determining the quantity of drilling fluid
discharged with cuttings, EPA is promulgating the use of the American
Petroleum Institute (API) Retort Method (Recommended Practice 13B-2)
with sampling procedures (i.e., Appendix 7 of subpart A of 40 CFR part
435). For determining when Coastal Cook Inlet, Alaska, operators
qualify for an exemption from the Coastal requirement of zero discharge
for SBF-cuttings, EPA is promulgating the use of the procedure outlined
in Appendix 1 of subpart D of 40 CFR part 435.
EPA Method 1654A, ASTM E-1367-92, and ISO 11734:1995 are
incorporated by reference into 40 CFR part 435 because they are
published methods that are widely available to the public.
Modifications to the anaerobic closed bottle biodegradation test (i.e.,
ISO 11734:1995) are provided in Appendix 4 of subpart A of 40 part 435.
The SPP toxicity test is given in Appendix 2 of subpart A of 40 part
435. Supplemental sediment preparation procedures for ASTM E-1367-92
are provided in Appendix 3 of subpart A of 40 CFR part 435. Reference
drilling fluid preparation procedures for ASTM E-1367-92 are provided
in Appendix 8 of subpart A of 40 CFR part 435. The text of the GC/MS
test, RPE test, and the API retort method are provided in Appendices 5-
7 of subpart A of 40 CFR part 435. The procedure for determining when
Coastal Cook Inlet operators qualify for an exemption from the Coastal
requirement of zero discharge for SBF-cuttings is provided in Appendix
1 of subpart D of 40 CFR part 435.
Appendix A to the Preamble--Abbreviations, Acronyms, and Other
Terms Used in This Preamble
Act--Clean Water Act
Agency--U.S. Environmental Protection Agency
AOGCC--Alaska Oil and Gas Conservation Commission
API--American Petroleum Institute
ANL--Argonne National Laboratory (DOE)
ASTM--American Society of Testing and Materials
BADCT--The best available demonstrated control technology, for new
sources under section 306 of the Clean Water Act.
BAT--The best available technology economically achievable, under
section 304(b)(2)(B) of the Clean Water Act.
bbl--barrel, 42 U.S. gallons
BCT--Best conventional pollutant control technology under section
304(b)(4)(B).
BMP--Best management practices under section 304(e) of the Clean
Water Act.
BOD--Biochemical oxygen demand.
BOE--Barrels of oil equivalent
BPJ--Best Professional Judgement
BPT--Best practicable control technology currently available, under
section 304(b)(1) of the Clean Water Act.
CERCLA--Comprehensive Environmental Response, Compensation, and
Liability Act
CFR--U.S. Code of Federal Regulations
Clean Water Act--Federal Water Pollution Control Act Amendments of
1972 as amended (33 U.S.C. 1251 et seq)
Conventional pollutants--Constituents of wastewater as determined by
section 304(a)(4) of the Act, including, but no limited to,
pollutants classified as biochemical oxygen demanding, suspended
solids, oil and grease, fecal coliform, and pH
Direct discharger--A facility which discharges or may discharge
pollutants to waters of the United States
D&B--Dun & Bradstreet
DOE--U.S. Department of Energy
DWD--Deep-water development model well
DWE--Deep-water exploratory model well
EMO--Enhanced Mineral Oil Drilling Fluid
EPA--U.S. Environmental Protection Agency
FR--Federal Register
GC--Gas Chromatography
GC/FID--Gas Chromatography with Flame Ionization Detection
GC/MS--Gas Chromatography with Mass Spectroscopy Detection
GOM--Gulf of Mexico
Indirect discharger--A facility that introduces wastewater into a
publicly owned treatment works.
IRFA--Initial Regulatory Flexibility Analysis
LC50 (or LC50)--The concentration of a test material that
is lethal to 50% of the test organisms in a bioassay
mg/l--milligrams per liter
MMS--U.S. Department of Interior, Minerals Management Service
NAF--Non-Aqueous Drilling Fluid (includes OBFs, EMOs, and SBFs)
Non-conventional pollutants--Pollutants that have not been
designated as either conventional pollutants or priority pollutants
NODA--Notice of Data Availability (65 FR 21548; April 21, 2000)
NOIA--National Ocean Industries Association
NOW--Nonhazardous Oilfield Waste
NPDES--National Pollutant Discharge Elimination System
NRDC--Natural Resources Defense Council, Inc.
NSPS--New source performance standards under section 306 of the
Clean Water Act
NTTAA--National Technology Transfer and Advancement Act
NWQI--Non-Water Quality Environmental Impacts
OBF--Oil-Based Drilling Fluid
OCS--Outer Continental Shelf
OMB--Office of Management and Budget
PAH--Polynuclear Aromatic Hydrocarbon
PDC--Polycrystalline Diamond Compact (drill bit)
POTW--Publicly Owned Treatment Works ppm--parts per million
PPA--Pollution Prevention Act of 1990
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 Act
PSNS--Pretreatment standards for new sources of indirect discharges,
under sections 307(b) and (c) of the Act
RFA--Regulatory Flexibility Act
ROC--Retention on Cuttings
RPE--Reverse Phase Extraction
SBA--U.S. Small Business Administration
SBF--Synthetic Based Drilling Fluid
SBF Development Document--Development Document for Final Effluent
Limitations Guidelines and Standards for Synthetic-Based Drilling
Fluids and other Non-Aqueous Drilling Fluids in the Oil and Gas
Extraction Point Source Category (EPA-821-B-00-013)
SBF Economic Analysis--Economic Analysis of Final Effluent
Limitations Guidelines and Standards for Synthetic-Based Drilling
Fluids and other Non-Aqueous Drilling Fluids in the Oil and Gas
Extraction Point Source Category (EPA-821-B-00-012)
SBF Environmental Assessment--Environmental Assessment of Final
Effluent Limitations Guidelines and Standards for Synthetic-Based
Drilling Fluids and other Non-Aqueous Drilling Fluids in the Oil and
Gas Extraction Point Source Category (EPA-821-B-00-014)
SBF Statistical Support Document--Statistical Analyses Supporting
Final Effluent Limitations Guidelines and Standards for Synthetic-
Based Drilling Fluids and other Non-Aqueous Drilling Fluids in the
Oil and Gas Extraction Point Source Category (EPA-821-B-00-015)
SBMRC--Synthetic Based Muds Research Consortium
SBREFA--Small Business Regulatory Enforcement Fairness Act
SIC--Standard Industrial Classification
SPP--Suspended Particulate Phase toxicity test (Appendix 2 to
Subpart A of 40 CFR 435)
[[Page 6895]]
SWD--Shallow-water development model well
SWE--Shallow-water exploratory model well
TSS--Total Suspended Solids
UMRA--Unfunded Mandates Reform Act
UIC--Underground Injection Control programs of the Safe Drinking
Water Act of 1974 as amended
U.S.C.--United States Code
WBF--Water-Based Drilling Fluid
List of Subjects
40 CFR Part 9
Reporting and recordkeeping requirements.
40 CFR Part 435
Environmental protection, Non-aqueous drilling fluids, Oil and gas
extraction, Pollution prevention, Synthetic based drilling fluids,
Waste treatment and disposal, Water non-dispersible drilling fluids,
Water pollution control.
Dated: December 28, 2000.
Carol M. Browner,
Administrator.
For the reasons set forth in this preamble, 40 CFR parts 9 and 435
are amended as follows:
PART 9--OMB APPROVALS UNDER THE PAPERWORK REDUCTION ACT
1. The authority citation for part 9 continues to read as follows:
Authority: 7 U.S.C. 135 et seq., 136-136y; 15 U.S.C. 2001, 2003,
2005, 2006, 2601-2671; 21 U.S.C. 331j, 346a, 348; 31 U.S.C. 9701; 33
U.S.C. 1251 et seq., 1311, 1313d, 1314, 1318, 1321, 1326, 1330,
1342, 1344, 1345 (d) and (e), 1361; E.O. 11735, 38 FR 21243, 3 CFR,
1971-1975 Comp. p. 973; 42 U.S.C. 241, 242b, 243, 246, 300f, 300g,
300g-1, 300g-2, 300g-3, 300g-4, 300g-5, 300g-6, 300j-1, 300j-2,
300j-3, 300j-4, 300j-9, 1857 et seq., 6901-6992k, 7401-7671q, 7542,
9601-9657, 11023, 11048.
2. In Sec. 9.1 the table is amended by adding entries in numerical
order under a new heading titled ``Oil and Gas Extraction Point Source
Category'' to read as follows:
Sec. 9.1 OMB approvals under the Paperwork Reduction Act.
* * * * *
------------------------------------------------------------------------
OMB control
40 CFR citation No.
------------------------------------------------------------------------
* * * * *
Oil and Gas Extraction Point Source Category:
435.13................................................. 2040-0230
435.15................................................. 2040-0230
435.43................................................. 2040-0230
435.45................................................. 2040-0230
* * * * *
------------------------------------------------------------------------
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, 1342 and
1361.
Subpart A--Offshore Subcategory
2. Section 435.11 is amended by revising paragraphs (b) through
(cc) and by adding paragraphs (dd) through (tt) to read as follows:
Sec. 435.11 Special definitions.
* * * * *
(b) Average of daily values for 30 consecutive days means the
average of the daily values obtained during any 30 consecutive day
period.
(c) Base fluid means the continuous phase or suspending medium of a
drilling fluid formulation.
(d) Base fluid retained on cuttings as applied to BAT effluent
limitations and NSPS refers to the American Petroleum Institute
Recommended Practice 13B-2 supplemented with the specifications,
sampling methods, and averaging method for retention values provided in
Appendix 7 of Subpart A of this part.
(e) Biodegradation rate as applied to BAT effluent limitations and
NSPS for drilling fluids and drill cuttings refers to the ISO
11734:1995 method: ``Water quality--Evaluation of the `ultimate'
anaerobic biodegradability of organic compounds in digested sludge--
Method by measurement of the biogas production (1995 edition)''
supplemented with modifications in Appendix 4 of 40 CFR part 435,
subpart A. 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 National Standards
Institute, 11 West 42nd Street, 13th Floor, New York, NY 10036. Copies
may be inspected at the Office of the Federal Register, 800 North
Capitol Street, NW., Suite 700, Washington, DC. A copy may also be
inspected at EPA's Water Docket, 401 M Street SW., Washington, DC
20460.
(f) Daily values as applied to produced water effluent limitations
and NSPS means the daily measurements used to assess compliance with
the maximum for any one day.
(g) Deck drainage means 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.
(h) Development facility means any fixed or mobile structure
subject to this subpart that is engaged in the drilling of productive
wells.
(i) 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,
100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies may be
inspected at the Office of the Federal Register, 800 North Capitol
Street, NW., Suite 700, Washington, DC. A copy may also be inspected at
EPA's Water Docket, 401 M Street SW., Washington, DC 20460.
(j) Domestic waste means 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.
(k) Drill cuttings means the particles generated by drilling into
subsurface geologic formations and carried out from the wellbore with
the drilling fluid. Examples of drill cuttings include small pieces of
rock varying in size and texture from fine silt to gravel. Drill
cuttings are generally generated from solids control equipment and
settle out and accumulate in quiescent areas in the solids control
equipment or other equipment processing drilling fluid (i.e.,
accumulated solids).
(1) Wet drill cuttings means the unaltered drill cuttings and
adhering drilling fluid and formation oil carried out from the wellbore
with the drilling fluid.
(2) Dry drill cuttings means the residue remaining in the retort
vessel after completing the retort procedure specified in appendix 7 of
subpart A of this part.
(l) Drilling fluid means the circulating fluid (mud) used in the
rotary drilling of wells to clean and condition the hole and to
counterbalance formation pressure. Classes of drilling fluids are:
(1) Water-based drilling fluid means the continuous phase and
suspending
[[Page 6896]]
medium for solids is a water-miscible fluid, regardless of the presence
of oil.
(2) Non-aqueous drilling fluid means the continuous phase and
suspending medium for solids is a water-immiscible fluid, such as
oleaginous materials (e.g., mineral oil, enhanced mineral oil,
paraffinic oil, C16-C18 internal olefins, and
C8-C16 fatty acid/2-ethylhexyl esters).
(i) Oil-based means the continuous phase of the drilling fluid
consists of diesel oil, mineral oil, or some other oil, but contains no
synthetic material or enhanced mineral oil.
(ii) Enhanced mineral oil-based means the continuous phase of the
drilling fluid is enhanced mineral oil.
(iii) Synthetic-based means the continuous phase of the drilling
fluid is a synthetic material or a combination of synthetic materials.
(m) Enhanced mineral oil as applied to enhanced mineral oil-based
drilling fluid means a petroleum distillate which has been highly
purified and is distinguished from diesel oil and conventional mineral
oil in having a lower polycyclic aromatic hydrocarbon (PAH) content.
Typically, conventional mineral oils have a PAH content on the order of
0.35 weight percent expressed as phenanthrene, whereas enhanced mineral
oils typically have a PAH content of 0.001 or lower weight percent PAH
expressed as phenanthrene.
(n) 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.
(o) Formation oil means the oil from a producing formation which is
detected in the drilling fluid, as determined by the GC/MS compliance
assurance method specified in appendix 5 of subpart A of this part when
the drilling fluid is analyzed before being shipped offshore, and as
determined by the RPE method specified in appendix 6 of subpart A of
this part when the drilling fluid is analyzed at the offshore point of
discharge. Detection of formation oil by the RPE method may be
confirmed by the GC/MS compliance assurance method, and the results of
the GC/MS compliance assurance method shall supercede those of the RPE
method.
(p) M9IM means those offshore facilities continuously manned by
nine (9) or fewer persons or only intermittently manned by any number
of persons.
(q) M10 means those offshore facilities continuously manned by ten
(10) or more persons.
(r) 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 for
determination of cadmium and mercury content.
(s) 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.
(t) Maximum weighted mass ratio averaged over all NAF well sections
for BAT effluent limitations and NSPS for base fluid retained on
cuttings means the weighted average base fluid retention for all NAF
well sections as determined by the API Recommended Practice 13B-2,
using the methods and averaging calculations presented in Appendix 7 of
subpart A of this part.
(u) Method 1654A refers to Method 1654, Revision A, entitled ``PAH
Content of Oil by HPLC/UV,'' December 1992, which is published in
Methods for the Determination of Diesel, Mineral, and Crude Oils in
Offshore Oil and Gas Industry Discharges, EPA-821-R-92-008. 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 National Technical Information Service,
Springfield, VA 22161, 703-605-6000. Copies may be inspected at the
Office of the Federal Register, 800 North Capitol Street, NW., Suite
700, Washington, DC. A copy may also be inspected at EPA's Water
Docket, 401 M Street SW., Washington, DC 20460.
(v) 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. 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.
(w)(1) 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) Water area as used in ``site'' in 40 CFR 122.29 and 122.2 means
the water area and water body floor beneath any exploratory,
development, or production facility where such facility is conducting
its exploratory, development or production activities.
(ii) Significant site preparation work as used in 40 CFR 122.29
means the process of surveying, clearing or preparing an area of the
water body floor for the purpose of constructing or placing a
development or production facility on or over the site.
(2) ``New Source'' does not include facilities covered by an
existing NPDES permit immediately prior to the effective date of these
guidelines pending EPA issuance of a new source NPDES permit.
(x) No discharge of free oil means that waste streams may not be
discharged that contain free oil as evidenced by the monitoring method
specified for that particular stream, e.g., deck drainage or
miscellaneous discharges cannot be discharged when they would cause a
film or sheen upon or discoloration of the surface of the receiving
water; drilling fluids or cuttings may not be discharged when they fail
the static sheen test defined in Appendix 1 of subpart A of this part.
(y) Parameters that are regulated in this Subpart and listed with
approved methods of analysis in Table 1B at 40 CFR 136.3 are defined as
follows:
(1) Cadmium means total cadmium.
(2) Chlorine means total residual chlorine.
(3) Mercury means total mercury.
(4) Oil and Grease means total recoverable oil and grease.
(z) PAH (as phenanthrene) means polynuclear aromatic hydrocarbons
reported as phenanthrene.
(aa) Produced sand means the 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.
(bb) Produced water means 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.
(cc) 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.
(dd) Sanitary waste means the human body waste discharged from
toilets and
[[Page 6897]]
urinals located within facilities subject to this Subpart.
(ee) Sediment toxicity as applied to BAT effluent limitations and
NSPS for drilling fluids and drill cuttings refers to the ASTM E 1367-
92 method: ``Standard Guide for Conducting 10-day Static Sediment
Toxicity Tests with Marine and Estuarine Amphipods,'' 1992, with
Leptocheirus plumulosus as the test organism and sediment preparation
procedures specified in Appendix 3 of 40 CFR part 435, subpart A. 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,
100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies may be
inspected at the Office of the Federal Register, 800 North Capitol
Street, NW., Suite 700, Washington, DC. A copy may also be inspected at
EPA's Water Docket, 401 M Street SW., Washington, DC 20460.
(ff) Solids control equipment means shale shakers, centrifuges, mud
cleaners, and other equipment used to separate drill cuttings and/or
stock barite solids from drilling fluid recovered from the wellbore.
(gg) SPP 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 subpart A of this part.
(hh) Static sheen test means 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 of subpart A of this part.
(ii) Stock barite means the barite that was used to formulate a
drilling fluid.
(jj) Stock base fluid means the base fluid that was used to
formulate a drilling fluid.
(kk) Synthetic material as applied to synthetic-based drilling
fluid means material produced by the reaction of specific purified
chemical feedstock, as opposed to the traditional base fluids such as
diesel and mineral oil which are derived from crude oil solely through
physical separation processes. Physical separation processes include
fractionation and distillation and/or minor chemical reactions such as
cracking and hydro processing. Since they are synthesized by the
reaction of purified compounds, synthetic materials suitable for use in
drilling fluids are typically free of polycyclic aromatic hydrocarbons
(PAH's) but are sometimes found to contain levels of PAH up to 0.001
weight percent PAH expressed as phenanthrene. Internal olefins and
vegetable esters are two examples of synthetic materials suitable for
use by the oil and gas extraction industry in formulating drilling
fluids. Internal olefins are synthesized from the isomerization of
purified straight-chain (linear) hydrocarbons such as C16-
C18 linear alpha olefins. C16-C18
linear alpha olefins are unsaturated hydrocarbons with the carbon to
carbon double bond in the terminal position. Internal olefins are
typically formed from heating linear alpha olefins with a catalyst. The
feed material for synthetic linear alpha olefins is typically purified
ethylene. Vegetable esters are synthesized from the acid-catalyzed
esterification of vegetable fatty acids with various alcohols. EPA
listed these two branches of synthetic fluid base materials to provide
examples, and EPA does not mean to exclude other synthetic materials
that are either in current use or may be used in the future. A
synthetic-based drilling fluid may include a combination of synthetic
materials.
(ll) Well completion fluids means 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.
(mm) Well treatment fluids means any fluid used to restore or
improve productivity by chemically or physically altering hydrocarbon-
bearing strata after a well has been drilled.
(nn) Workover fluids means salt solutions, weighted brines,
polymers, or other specialty additives used in a producing well to
allow for maintenance, repair or abandonment procedures.
(oo) 4-day LC50 as applied to the sediment toxicity BAT
effluent limitations and NSPS means the concentration (milligrams/
kilogram dry sediment) of the drilling fluid in sediment that is lethal
to 50 percent of the Leptocheirus plumulosus test organisms exposed to
that concentration of the drilling fluids after four days of constant
exposure.
(pp) 10-day LC50 as applied to the sediment toxicity BAT
effluent limitations and NSPS means the concentration (milligrams/
kilogram dry sediment) of the base fluid in sediment that is lethal to
50 percent of the Leptocheirus plumulosus test organisms exposed to
that concentration of the base fluids after ten days of constant
exposure.
(qq) 96-hour LC50 means 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.
(rr) C16-C18 internal olefin means a 65/35
blend, proportioned by mass, of hexadecene and octadecene,
respectively. Hexadecene is an unsaturated hydrocarbon with a carbon
chain length of 16, an internal double carbon bond, and is represented
by the Chemical Abstracts Service (CAS) No. 26952-14-7. Octadecene is
an unsaturated hydrocarbon with a carbon chain length of 18, an
internal double carbon bond, and is represented by the Chemical
Abstracts Service (CAS) No. 27070-58-2. (Properties available from the
Chemical Abstracts Service, 2540 Olentangy River Road, PO Box 3012,
Columbus, OH, 43210).
(ss) C16-C18 internal olefin drilling fluid
means a C16-C18 internal olefin drilling fluid
formulated as specified in Appendix 8 of subpart A of this part.
(tt) C12-C14 ester and C8 ester
means the fatty acid/2-ethylhexyl esters with carbon chain lengths
ranging from 8 to 16 and represented by the Chemical Abstracts Service
(CAS) No. 135800-37-2. (Properties available from the Chemical
Abstracts Service, 2540 Olentangy River Road, PO Box 3012, Columbus,
OH, 43210)
3. In Sec. 435.12 the table is amended by removing the entries
``Drilling muds'' and ``Drill cuttings'' and by adding new entries
(after ``Deck drainage'') for ``Water based'' and ``Non-aqueous'' to
read as follows:
Sec. 435.12 Effluent limitations guidelines representing the degree of
effluent reduction attainable by the application of the best
practicable control technology currently available (BPT).
* * * * *
[[Page 6898]]
BPT Effluent Limitations--Oil and Grease
[In milligrams per liter]
----------------------------------------------------------------------------------------------------------------
Average of values for 30
Pollutant parameter waste source Maximum for any 1 day consecutive days shall Residual chlorine
not exceed minimum for any 1 day
----------------------------------------------------------------------------------------------------------------
* * * * * *
*
Water-based:
Drilling fluids.................. (\1\)................... (\1\)................... NA
Drill Cuttings................... (\1\)................... (\1\)................... NA
Non-aqueous:
Drilling fluids.................. No discharge............ No discharge............ NA
Drill Cuttings................... (\1\)................... (\1\)................... NA
* * * * * *
*
----------------------------------------------------------------------------------------------------------------
\1\ No discharge of free oil.
* * * * *
4. In Sec. 435.13 the table is amended by revising entry (B) under
``Drilling fluids and drill cuttings'' and by revising footnote 2 and
adding footnotes 5-11 to read as follows:
Sec. 435.13 Effluent limitations guidelines representing the degree of
effluent reduction attainable by the application of the best available
technology economically achievable (BAT).
* * * * *
Bat Effluent Limitations
------------------------------------------------------------------------
Pollutant BAT effluent
Waste source parameter limitation
------------------------------------------------------------------------
* * * *
* * *
Drilling fluids and drill
cuttings:
* * * *
* * *
(B) For facilities located
beyond 3 miles from shore:
Water-based drilling SPP Toxicity..... Minimum 96-hour LC50
fluids and associated of the SPP Toxicity
drill cuttings. Test \2\ shall be 3%
by volume.
Free oil......... No discharge.\3\
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.
Non-aqueous drilling ................. No discharge.
fluids (NAFs).
Drill cuttings associated with
non-aqueous drilling fluids:
Stock Limitations (C16-C18 Mercury.......... 1 mg/kg dry weight
internal olefin). maximum in the stock
barite.
Cadmium.......... 3 mg/kg dry weight
maximum in the stock
barite.
Polynuclear PAH mass ratio \5\
Aromatic shall not exceed
Hydrocarbons 1x10-5.
(PAH).
Sediment toxicity Base fluid sediment
toxicity ratio \6\
shall not exceed
1.0.
Biodegradation Biodegradation rate
rate. ratio \7\ shall not
exceed 1.0.
Discharge Limitations..... Diesel oil....... No discharge.
SPP Toxicity..... Minimum 96-hour LC50
of the SPP Toxicity
Test \2\ shall be 3%
by volume.
Sediment toxicity Drilling fluid
sediment toxicity
ratio \8\ shall not
exceed 1.0.
Formation Oil.... No discharge.\9\
Base fluid For NAFs that meet
retained on the stock
cuttings. limitations (C16-C18
internal olefin) in
this table, the
maximum weighted
mass ratio averaged
over all NAF well
sections shall be
6.9 g-NAF base fluid/
100 g-wet drill
cuttings.\10\
For NAFs that meet
the C12-C14 ester or
C8 ester stock
limitations in
footnote 11 of this
table, the maximum
weighted mass ratio
averaged over all
NAF well sections
shall be 9.4 g-NAF
base fluid/100 g-wet
drill cuttings.
[[Page 6899]]
* * * *
* * *
------------------------------------------------------------------------
* * * *
* * *
\2\ As determined by the suspended particulate phase (SPP) toxicity test
(Appendix 2 of subpart A of this part).
\3\ As determined by the static sheen test (Appendix 1 of subpart A of
this part).
* * * *
* * *
\5\ PAH mass ratio = Mass (g) of PAH (as phenanthrene)/Mass (g) of stock
base fluid as determined by EPA Method 1654, Revision A, (specified at
Sec. 435.11(u)) entitled ``PAH Content of Oil by HPLC/UV,'' December
1992, which is published in Methods for the Determination of Diesel,
Mineral, and Crude Oils in Offshore Oil and Gas Industry Discharges,
EPA-821-R-92-008. 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 National Technical
Information Service, Springfield, VA 22161, 703-605-6000. Copies may
be inspected at the Office of the Federal Register, 800 North Capitol
Street, NW., Suite 700, Washington, DC. A copy may also be inspected
at EPA's Water Docket, 401 M Street SW., Washington, DC 20460.
\6\ Base fluid sediment toxicity ratio = 10-day LC50 of C16-C18 internal
olefin/10-day LC50 of stock base fluid as determined by ASTM E 1367-92
[specified at Sec. 435.11(ee)] method: ``Standard Guide for
Conducting 10-day Static Sediment Toxicity Tests with Marine and
Estuarine Amphipods,'' 1992, after preparing the sediment according to
the method specified in Appendix 3 of subpart A of this part. 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,
100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies may be
inspected at the Office of the Federal Register, 800 North Capitol
Street, NW., Suite 700, Washington, DC. A copy may also be inspected
at EPA's Water Docket, 401 M Street SW., Washington, DC 20460.
\7\ Biodegradation rate ratio = Cumulative gas production (ml) of C16-
C18 internal olefin/Cumulative gas production (ml) of stock base
fluid, both at 275 days as determined by ISO 11734:1995 [specified at
Sec. 435.11(e)] method: ``Water quality--Evaluation of the `ultimate'
anaerobic biodegradability of organic compounds in digested sludge--
Method by measurement of the biogas production (1995 edition)'' as
modified for the marine environment (Appendix 4 of subpart A of this
part). 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 National Standards
Institute, 11 West 42nd Street, 13th Floor, New York, NY 10036. Copies
may be inspected at the Office of the Federal Register, 800 North
Capitol Street, NW., Suite 700, Washington, DC. A copy may also be
inspected at EPA's Water Docket, 401 M Street SW., Washington, DC
20460.
\8\ Drilling fluid sediment toxicity ratio = 4-day LC50 of C16-C18
internal olefin drilling fluid/4-day LC50 of drilling fluid removed
from drill cuttings at the solids control equipment as determined by
ASTM E 1367-92 (specified at Sec. 435.11(ee)) method: ``Standard
Guide for Conducting 10-day Static Sediment Toxicity Tests with Marine
and Estuarine Amphipods,'' 1992, after preparing the sediment
according to the method specified in Appendix 3 of subpart A of this
part. 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, 100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies
may be inspected at the Office of the Federal Register, 800 North
Capitol Street, NW., Suite 700, Washington, DC. A copy may also be
inspected at EPA's Water Docket, 401 M Street SW., Washington, DC
20460.
\9\ As determined before drilling fluids are shipped offshore by the GC/
MS compliance assurance method (Appendix 5 of subpart A of this part),
and as determined prior to discharge by the RPE method (Appendix 6 of
subpart A of this part) applied to drilling fluid removed from drill
cuttings. If the operator wishes to confirm the results of the RPE
method (Appendix 6 of subpart A of this part), the operator may use
the GC/MS compliance assurance method (Appendix 5 of subpart A of this
part). Results from the GC/MS compliance assurance method (Appendix 5
of subpart A of this part) shall supercede the results of the RPE
method (Appendix 6 of subpart A of this part).
\10\ Maximum permissible retention of non-aqueous drilling fluid (NAF)
base fluid on wet drill cuttings averaged over drilling intervals
using NAFs as determined by the API retort method (Appendix 7 of
subpart A of this part). This limitation is applicable for NAF base
fluids that meet the base fluid sediment toxicity ratio (Footnote 6),
biodegradation rate ratio (Footnote 7), PAH, mercury, and cadmium
stock limitations (C16-C18 internal olefin) defined above in this
table.
\11\ Maximum permissible retention of non-aqueous drilling fluid (NAF)
base fluid on wet drill cuttings average over drilling intervals using
NAFs as determined by the API retort method (Appendix 7 of subpart A
of this part). This limitation is applicable for NAF base fluids that
meet the ester base fluid sediment toxicity ratio and ester
biodegradation rate ratio stock limitations defined as: (a) ester base
fluid sediment toxicity ratio = 10-day LC50 of C12-C14 ester or C8
ester /10-day LC50 of stock base fluid as determined by ASTM E 1367-92
(specified at Sec. 435.11(ee)) method: ``Standard Guide for
Conducting 10-day Static Sediment Toxicity Tests with Marine and
Estuarine Amphipods,'' 1992, after preparing the sediment according to
the method specified in Appendix 3 of subpart A of this part. 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,
100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies may be
inspected at the Office of the Federal Register, 800 North Capitol
Street, NW., Suite 700, Washington, DC. A copy may also be inspected
at EPA's Water Docket, 401 M Street SW., Washington, DC 20460. (b)
ester biodegradation rate ratio = Cumulative gas production (ml) of
C12-C14 ester or C8 ester/Cumulative gas production (ml) of stock base
fluid, both at 275 days as determined by ISO 11734:1995 (specified at
Sec. 435.11(e)) method: ``Water quality--Evaluation of the `ultimate'
anaerobic biodegradability of organic compounds in digested sludge--
Method by measurement of the biogas production (1995 edition)'' as
modified for the marine environment (Appendix 4 of subpart A of this
part). 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 National Standards
Institute, 11 West 42nd Street, 13th Floor, New York, NY 10036. Copies
may be inspected at the Office of the Federal Register, 800 North
Capitol Street, NW., Suite 700, Washington, DC. A copy may also be
inspected at EPA's Water Docket, 401 M Street SW., Washington, DC
20460. (c) PAH mass ratio (Footnote 5), mercury, and cadmium stock
limitations (C16-C18 internal olefin) defined above in this table.
5. In Sec. 435.14 the table is amended by revising entry (B) under
``Drilling fluids and drill cuttings'' to read as follows:
Sec. 435.14 Effluent limitations guidelines representing the degree of
effluent reduction attainable by the application of the best
conventional pollutant control technology (BCT).
* * * * *
BCT Effluent Limitations
------------------------------------------------------------------------
Pollutant
Waste source parameter BCT effluent limitation
------------------------------------------------------------------------
* * * *
* * *
Drilling fluids and drill
cuttings:
[[Page 6900]]
* * * *
* * *
(B) For facilities located
beyond 3 miles from shore:
Water-based drilling Free Oil....... No discharge.\2\
fluids and associated
drill cuttings.
Non-aqueous drilling ............... No discharge.
fluids.
Drill cuttings associated Free Oil....... No discharge.\2\
with non-aqueous
drilling fluids.
------------------------------------------------------------------------
* * * *
* * *
\2\ As determined by the static sheen test (Appendix 1 of Subpart A of
this part).
* * * *
* * *
6. In Sec. 435.15 the table is amended by revising entry (B) under
``Drilling fluids and drill cuttings'' and by revising footnote 2 and
adding footnotes 5-11 to read as follows:
Sec. 435.15 Standards of performance for new sources (NSPS).
* * * * *
New Source Performance Standards (NSPS)
------------------------------------------------------------------------
Pollutant
Waste source parameter NSPS
------------------------------------------------------------------------
* * * *
* * *
Drilling fluids and drill
cuttings:
* * * *
* * *
(B) For facilities located
beyond 3 miles from shore:
Water-based drilling SPP Toxicity..... Minimum 96-hour LC50
fluids and associated of the SPP Toxicity
drill cuttings. Test 2 shall be 3%
by volume.
Free oil......... No discharge.3
Diesel oil....... No charge.
Mercury.......... 1mg/kg dry weight
maximum in the stock
barite.
Cadmium.......... 3 mg/kg dry weight
maximum in the stock
barite.
Non-aqueous drilling ................. No charge.
fluids.
Drill cuttings associated with
non-aqueous drilling fluids:
Stock Limitations (C16-C18 Mercury.......... 1mg/kg dry weight
internal olefin. maximum in the stock
barite.
Cadmium.......... 3 mg/kg dry weight
maximum in the stock
barite.
Polynuclear PAH mass ratio5 shall
Aromatic not exceed 1 x 10-5
Hydrocarbons
(PAH).
Sediment toxicity Base fluid sediment
toxicity ratio 6
shall not exceed
1.0.
Biodegradation Biodegradation rate
rate. ratio7 shall not
exceed 1.0.
Discharge Limitations..... Diesel oil....... No discharge.
SPP Toxicity..... Minimum 96-hour LC50
of the SPP Toxicity
Test 2 shall be 3%
by volume.
Sediment toxicity Drilling fluid
sediment toxicity
ratio 8 shall not
exceed 1.0.
Formation Oil.... No discharge.9
Base fluid For NAFs that meet
retained on the stock
cuttings. limitations (C16-C18
internal olefin) in
this table, the
maximum weighted
mass ratio averaged
over all NAF well
sections shall be
6.9 g-NAF base fluid/
100 g-wet drill
cuttings.10
For NAFs that meet
the C12-C14 ester or
C8 ester stock
limitations in
footnote 11 of this
table, the maximum
weighted mass ratio
averaged over all
NAF well sections
shall be 9.4 g-NAF
base fluid/100 g-wet
drill cuttings.
* * * *
* * *
------------------------------------------------------------------------
* * * *
* * *
\2\ As determined by the suspended particulate phase (SPP) toxicity test
(Appendix 2 of subpart A of this part).
\3\ As determined by the static sheen test (appendix 1 of subpart A of
this part).
* * * *
* * *
\5\ PAH mass ratio = Mass (g) of PAH (as phenanthrene)/Mass (g) of stock
base fluid as determined by EPA Method 1654, Revision A, (specified at
Sec. 435.11(u)) entitled ``PAH Content of Oil by HPLC/UV,'' December
1992, which is published in Methods for the Determination of Diesel,
Mineral, and Crude Oils in Offshore Oil and Gas Industry Discharges,
EPA-821-R-92-008. 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 National Technical
Information Service, Springfield, VA 22161, 703-605-6000. Copies may
be inspected at the Office of the Federal Register, 800 North Capitol
Street, NW., Suite 700, Washington, DC. A copy may also be inspected
at EPA's Water Docket, 401 M Street SW., Washington, DC 20460.
[[Page 6901]]
\6\ Base fluid sediment toxicity ratio = 10-day LC50 of C16-C18 internal
olefin/10-day LC50 of stock base fluid as determined by ASTM E 1367-92
(specified at Sec. 435.11(ee)) method: ``Standard Guide for
Conducting 10-day Static Sediment Toxicity Tests with Marine and
Estuarine Amphipods,'' 1992, after preparing the sediment according to
the method specified in Appendix 3 of subpart A of this part. 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,
100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies may be
inspected at the Office of the Federal Register, 800 North Capitol
Street, NW., Suite 700, Washington, DC. A copy may also be inspected
at EPA's Water Docket, 401 M Street SW., Washington, DC 20460.
\7\ Biodegradation rate ratio = Cumulative gas production (ml) of C16-
C18 internal olefin/Cumulative gas production (ml) of stock base
fluid, both at 275 days as determined by ISO 11734:1995 (specified at
Sec. 435.11(e)) method: ``Water quality--Evaluation of the `ultimate'
anaerobic biodegradability of organic compounds in digested sludge--
Method by measurement of the biogas production (1995 edition)'' as
modified for the marine environment (Appendix 4 of subpart A of this
part). 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 National Standards
Institute, 11 West 42nd Street, 13th Floor, New York, NY 10036. Copies
may be inspected at the Office of the Federal Register, 800 North
Capitol Street, NW., Suite 700, Washington, DC. A copy may also be
inspected at EPA's Water Docket, 401 M Street SW., Washington, DC
20460.
\8\ Drilling fluid sediment toxicity ratio = 4-day LC50 of C16-C18
internal olefin drilling fluid/4-day LC50 of drilling fluid removed
from drill cuttings at the solids control equipment as determined by
ASTM E 1367-92 (specified at Sec. 435.11(ee)) method: ``Standard
Guide for Conducting 10-day Static Sediment Toxicity Tests with Marine
and Estuarine Amphipods,'' 1992, after preparing the sediment
according to the method specified in Appendix 3 of subpart A of this
part. 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, 100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies
may be inspected at the Office of the Federal Register, 800 North
Capitol Street, NW., Suite 700, Washington, DC. A copy may also be
inspected at EPA's Water Docket, 401 M Street SW., Washington, DC
20460.
\9\ As determined before drilling fluids are shipped offshore by the GC/
MS compliance assurance method (Appendix 5 of subpart A of this part),
and as determined prior to discharge by the RPE method (Appendix 6 of
subpart A of this part) applied to drilling fluid removed from drill
cuttings. If the operator wishes to confirm the results of the RPE
method (Appendix 6 of subpart A of this part), the operator may use
the GC/MS compliance assurance method (Appendix 5 of subpart A of this
part). Results from the GC/MS compliance assurance method (Appendix 5
of subpart A of this part) shall supercede the results of the RPE
method (Appendix 6 of subpart A of this part).
\10\ Maximum permissible retention of non-aqueous drilling fluid (NAF)
base fluid on wet drill cuttings averaged over drilling intervals
using NAFs as determined by the API retort method (Appendix 7 of
subpart A of this part). This limitation is applicable for NAF base
fluids that meet the base fluid sediment toxicity ratio (Footnote 6),
biodegradation rate ratio (Footnote 7), PAH, mercury, and cadmium
stock limitations (C16-C18 internal olefin) defined above in this
table.
\11\ Maximum permissible retention of non-aqueous drilling fluid (NAF)
base fluid on wet drill cuttings average over drilling intervals using
NAFs as determined by the API retort method (Appendix 7 of subpart A
of this part). This limitation is applicable for NAF base fluids that
meet the ester base fluid sediment toxicity ratio and ester
biodegradation rate ratio stock limitations defined as: (a) Ester base
fluid sediment toxicity ratio = 10-day LC50 of C12-C14 ester or C8
ester /10-day LC50 of stock base fluid as determined by ASTM E 1367-92
[specified at Sec. 435.11(ee)] method: ``Standard Guide for
Conducting 10-day Static Sediment Toxicity Tests with Marine and
Estuarine Amphipods,'' 1992, after preparing the sediment according to
the method specified in Appendix 3 of subpart A of this part. 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,
100 Barr Harbor Drive, West Conshohocken, PA, 19428. Copies may be
inspected at the Office of the Federal Register, 800 North Capitol
Street, NW., Suite 700, Washington, DC. A copy may also be inspected
at EPA's Water Docket, 401 M Street SW., Washington, DC 20460; (b)
Ester biodegradation rate ratio = Cumulative gas production (ml) of
C12-C14 ester or C8 ester/Cumulative gas production (ml) of stock base
fluid, both at 275 days as determined by ISO 11734:1995 (specified at
Sec. 435.11(e)) method: ``Water quality--Evaluation of the `ultimate'
anaerobic biodegradability of organic compounds in digested sludge--
Method by measurement of the biogas production (1995 edition)'' as
modified for the marine environment (Appendix 4 of subpart A of this
part). 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 National Standards
Institute, 11 West 42nd Street, 13th Floor, New York, NY 10036. Copies
may be inspected at the Office of the Federal Register, 800 North
Capitol Street, NW., Suite 700, Washington, DC. A copy may also be
inspected at EPA's Water Docket, 401 M Street SW., Washington, DC
20460; and (c) PAH mass ratio (Footnote 5), mercury, and cadmium stock
limitations (C16-C18 internal olefin) defined above in this table.
7. Subpart A of this part is amended by adding Appendices 3 through
8 as follows:
Appendix 3 to Subpart A of Part 435--Procedure for Mixing Base Fluids
with Sediments
This procedure describes a method for amending uncontaminated
and nontoxic (control) sediments with the base fluids that are used
to formulate synthetic-based drilling fluids and other non-aqueous
drilling fluids. Initially, control sediments shall be press-sieved
through a 2000 micron mesh sieve to remove large debris. Then press-
sieve the sediment through a 500 micron sieve to remove indigenous
organisms that may prey on the test species or otherwise confound
test results. Homogenize control sediment to limit the effects of
settling that may have occurred during storage. Sediments should be
homogenized before density determinations and addition of base fluid
to control sediment. Because base fluids are strongly hydrophobic
and do not readily mix with sediment, care must be taken to ensure
base fluids are thoroughly homogenized within the sediment. All
concentrations are weight-to-weight (mg of base fluid to kg of dry
control sediment). Sediment and base fluid mixing shall be
accomplished by using the following method.
1. Determine the wet to dry ratio for the control sediment by
weighing approximately 10 g subsamples of the screened and
homogenized wet sediment into tared aluminum weigh pans. Dry
sediment at 105 deg.C for 18-24 h. Remove sediment and cool in a
desiccator until a constant weight is achieved. Re-weigh the samples
to determine the dry weight. Determine the wet/dry ratio by dividing
the net wet weight by the net dry weight:
[Wet Sediment Weight (g)]/[Dry Sediment Weight (g)] = Wet to Dry
Ratio [1]
2. Determine the density (g/mL) of the wet control or dilution
sediment. This shall be used to determine total volume of wet
sediment needed for the various test treatments.
[Mean Wet Sediment Weight (g)]/[Mean Wet Sediment Volume (mL)] = Wet
Sediment Density (g/mL) [2]
3. To determine the amount of base fluid needed to obtain a test
concentration of 500 mg base fluid per kg dry sediment use the
following formulas:
Determine the amount of wet sediment required:
[Wet Sediment Density (g/mL)] x [Volume of Sediment Required per
Concentration (mL)] = Weight Wet Sediment Required per Conc. (g)
[3]
Determine the amount of dry sediment in kilograms (kg) required
for each concentration:
{[Wet Sediment per Concentration (g)]/[Mean Wet to Dry Ratio]} x
(1kg/1000g) = Dry Weight Sediment (kg) [4]
Finally, determine the amount of base fluid required to spike
the control sediment at each concentration:
[Conc. Desired (mg/kg)] x [Dry Weight Sediment (kg)] = Base Fluid
Required (mg) [5]
For spiking test substances other than pure base fluids (e.g.,
whole mud formulations), determine the spike amount as follows:
[Conc. Desired (mL/kg)] x [Dry Weight Sediment (kg)] x [Test
Substance Density (g/mL)] = Test Substance Required (g) [6]
4. For primary mixing, place appropriate amounts of weighed base
fluid into stainless mixing bowls, tare the vessel weight, then add
sediment and mix with a high-shear dispersing impeller for 9
minutes. The concentration of base fluid in sediment from this mix,
rather than the nominal concentration, shall be used in calculating
LC50 values.
5. Tests for homogeneity of base fluid in sediment are to be
performed during the procedure development phase. Because of
[[Page 6902]]
difficulty of homogeneously mixing base fluid with sediment, it is
important to demonstrate that the base fluid is evenly mixed with
sediment. The sediment shall be analyzed for total petroleum
hydrocarbons (TPH) using EPA Methods 3550A and 8015M, with samples
taken both prior to and after distribution to replicate test
containers. Base-fluid content is measured as TPH. After mixing the
sediment, a minimum of three replicate sediment samples shall be
taken prior to distribution into test containers. After the test
sediment is distributed to test containers, an additional three
sediment samples shall be taken from three test containers to ensure
proper distribution of base fluid within test containers. Base-fluid
content results shall be reported within 48 hours of mixing. The
coefficient of variation (CV) for the replicate samples must be less
than 20%. If base-fluid content results are not within the 20% CV
limit, the test sediment shall be remixed. Tests shall not begin
until the CV is determined to be below the maximum limit of 20%.
During the test, a minimum of three replicate containers shall be
sampled to determine base-fluid content during each sampling period.
6. Mix enough sediment in this way to allow for its use in the
preparation of all test concentrations and as a negative control.
When commencing the sediment toxicity test, range-finding tests may
be required to determine the concentrations that produce a toxic
effect if these data are otherwise unavailable. The definitive test
shall bracket the LC50, which is the desired endpoint.
The results for the base fluids shall be reported in mg of base
fluid per kg of dry sediment.
References
American Society for Testing and Materials (ASTM). 1996.
Standard Guide for Collection, Storage, Characterization, and
Manipulation of Sediments for Toxicological Testing. ASTM E 1391-94.
Annual Book of ASTM Standards, Volume 11.05, pp. 805-825.
Ditsworth, G.R., D.W. Schults and J.K.P. Jones. 1990.
Preparation of benthic substrates for sediment toxicity testing,
Environ. Toxicol. Chem. 9:1523-1529.
Suedel, B.C., J.H. Rodgers, Jr. and P.A. Clifford. 1993.
Bioavailability of fluoranthene in freshwater sediment toxicity
tests. Environ. Toxicol. Chem. 12:155-165.
U.S. EPA. 1994. Methods for Assessing the Toxicity of Sediment-
associated Contaminants with Estuarine and Marine Amphipods. EPA/
600/R-94/025. Office of Research and Development, Washington, DC.
Appendix 4 to Subpart A of Part 435--Determination of Biodegradation of
Synthetic Base Fluids in a Marine Closed Bottle Test System: Summary of
Modifications to ISO 11734:1995
The six modifications specified in this Appendix shall apply to
the determination of the biodegradability of synthetic base fluids
as measured by ISO 11734:1995. These modifications make the test
more applicable to a marine environment and are listed below:
1. The laboratory shall use sea water in place of freshwater
media.
1.1 The sea water may be either natural or synthetic. The
allowable salinity range is 20-30 ppt.
1.2 To reduce the shock to the microorganisms in the sediment,
the salinity of the sediment's porewater shall be between 20-30 ppt.
2. The laboratory shall use natural marine or estuarine
sediments in place of digested sludge as an inoculum. The VS of the
sediments must be no less than 2%.
2.1 Sediment should be used for testing as soon as possible
after field collection. If required, the laboratory can store the
sediment for a maximum period of two months prior to use. The test
sediment shall be stored in the dark at 4 deg.C.
2.2 The laboratory shall use the sediment mixing procedure
specified in Appendix 3 to Subpart A of part 435 to spike the test
sediment with base fluids. The final concentration will be 2000 mg
carbon/Kg dry weight sediment. No less than 25 g dry weight of the
spiked sediment shall be used per 125 ml serum bottle. The volume of
sediment and seawater in the bottle shall be 75 ml.
3. The temperature of incubation shall be
291 deg.C.
4. The pH is maintained at the level of natural sea water, not
at 7.0 as referenced in ISO 11734:1995.
5. The optional use of a trace metals solution as specified in
method ISO 11734:1995 shall not be used as part of these test
modifications.
6. The laboratory shall conduct the test for 275 days. The
laboratory may seek approval of alternate test durations under the
approval procedures specified at 40 CFR 136.4 and 136.5. Any
modification of this method, beyond those expressly permitted, shall
be considered a major modification subject to application and
approval of alternate test procedures under 40 CFR 136.4 and 136.5.
Appendix 5 to Subpart A of Part 435--Determination of Crude Oil
Contamination in Non-Aqueous Drilling Fluids by Gas Chromatography/Mass
Spectrometry (GC/MS)
1.0 Scope and Application
1.1 This method determines crude (formation) oil contamination,
or other petroleum oil contamination, in non-aqueous drilling fluids
(NAFs) by comparing the gas chromatography/mass spectrometry (GC/MS)
fingerprint scan and extracted ion scans of the test sample to that
of an uncontaminated sample.
1.2 This method can be used for monitoring oil contamination of
NAFs or monitoring oil contamination of the base fluid used in the
NAF formulations.
1.3 Any modification of this method beyond those expressly
permitted shall be considered as a major modification subject to
application and approval of alternative test procedures under 40 CFR
136.4 and 136.5.
1.4 The gas chromatography/mass spectrometry portions of this
method are restricted to use by, or under the supervision of
analysts experienced in the use of GC/MS and in the interpretation
of gas chromatograms and extracted ion scans. Each laboratory that
uses this method must generate acceptable results using the
procedures described in Sections 7, 9.2, and 12 of this appendix.
2.0 Summary of Method
2.1 Analysis of NAF for crude oil contamination is a step-wise
process. The analyst first performs a qualitative assessment of the
presence or absence of crude oil in the sample. If crude oil is
detected during this qualitative assessment, the analyst must
perform a quantitative analysis of the crude oil concentration.
2.2 A sample of NAF is centrifuged to obtain a solids free
supernate.
2.3 The test sample is prepared by removing an aliquot of the
solids free supernate, spiking it with internal standard, and
analyzing it using GC/MS techniques. The components are separated by
the gas chromatograph and detected by the mass spectrometer.
2.4 Qualitative identification of crude oil contamination is
performed by comparing the Total Ion Chromatograph (TIC) scans and
Extracted Ion Profile (EIP) scans of test sample to that of
uncontaminated base fluids, and examining the profiles for
chromatographic signatures diagnostic of oil contamination.
2.5 The presence or absence of crude oil contamination observed
in the full scan profiles and selected extracted ion profiles
determines further sample quantitation and reporting requirements.
2.6 If crude oil is detected in the qualitative analysis,
quantitative analysis must be performed by calibrating the GC/MS
using a designated NAF spiked with known concentrations of a
designated oil.
2.7 Quality is assured through reproducible calibration and
testing of GC/MS system and through analysis of quality control
samples.
3.0 Definitions
3.1 A NAF is one in which the continuous-- phase is a water
immiscible fluid such as an oleaginous material (e.g., mineral oil,
enhance mineral oil, paraffinic oil, or synthetic material such as
olefins and vegetable esters).
3.2 TIC--Total Ion Chromatograph.
3.3 EIP--Extracted Ion Profile.
3.4 TCB--1,3,5-trichlorobenzene is used as the internal
standard in this method.
3.5 SPTM--System Performance Test Mix standards are used to
establish retention times and monitor detection levels.
4.0 Interferences and Limitations
4.1 Solvents, reagents, glassware, and other sample processing
hardware may yield artifacts and/or elevated baselines causing
misinterpretation of chromatograms.
4.2 All Materials used in the analysis shall be demonstrated to
be free from interferences by running method blanks. Specific
selection of reagents and purification of solvents by distillation
in all-glass systems may be required.
4.3 Glassware shall be cleaned by rinsing with solvent and
baking at 400 deg.C for a minimum of 1 hour.
[[Page 6903]]
4.4 Interferences may vary from source to source, depending on
the diversity of the samples being tested.
4.5 Variations in and additions of base fluids and/or drilling
fluid additives (emulsifiers, dispersants, fluid loss control
agents, etc.) might also cause interferences and misinterpretation
of chromatograms.
4.6 Difference in light crude oils, medium crude oils, and
heavy crude oils will result in different responses and thus
different interpretation of scans and calculated percentages.
5.0 Safety
5.1 The toxicity or carcinogenicity of each reagent used in
this method has not been precisely determined; however each chemical
shall be treated as a potential health hazard. Exposure to these
chemicals should be reduced to the lowest possible level.
5.2 Unknown samples may contain high concentration of volatile
toxic compounds. Sample containers should be opened in a hood and
handled with gloves to prevent exposure. In addition, all sample
preparation should be conducted in a fume hood to limit the
potential exposure to harmful contaminates.
5.3 This method does not address all safety issues associated
with its use. The laboratory is responsible for maintaining a safe
work environment and a current awareness file of OSHA regulations
regarding the safe handling of the chemicals specified in this
method. A reference file of material safety data sheets (MSDSs)
shall be available to all personnel involved in these analyses.
Additional references to laboratory safety can be found in
References 16.1 through 16.3.
5.4 NAF base fluids may cause skin irritation, protective
gloves are recommended while handling these samples.
6.0 Apparatus and Materials
Note: Brand names, suppliers, and part numbers are for
illustrative purposes only. No endorsement is implied. Equivalent
performance may be achieved using apparatus and materials other than
those specified here, but demonstration of equivalent performance
meeting the requirements of this method is the responsibility of the
laboratory.
6.1 Equipment for glassware cleaning.
6.1.1 Laboratory sink with overhead fume hood.
6.1.2 Kiln--Capable of reaching 450 deg.C within 2 hours and
holding 450 deg.C within 10 deg.C, with temperature
controller and safety switch (Cress Manufacturing Co., Santa Fe
Springs, CA B31H or X31TS or equivalent).
6.2 Equipment for sample preparation.
6.2.1 Laboratory fume hood.
6.2.2 Analytical balance--Capable of weighing 0.1 mg.
6.2.3 Glassware.
6.2.3.1 Disposable pipettes--Pasteur, 150 mm long by 5 mm ID
(Fisher Scientific 13-678-6A, or equivalent) baked at 400 deg.C for
a minimum of 1 hour.
6.2.3.2 Glass volumetric pipettes or gas tight syringes--1.0-mL
1% and 0.5-mL 1%.
6.2.3.3 Volumetric flasks--Glass, class A, 10-mL, 50-mL and
100-mL.
6.2.3.4--Sample vials--Glass, 1- to 3-mL (baked at 400 deg.C
for a minimum of 1 hour) with PTFE-lined screw or crimp cap.
6.2.3.5 Centrifuge and centrifuge tubes--Centrifuge capable of
10,000 rpm, or better, (International Equipment Co., IEC Centra MP4
or equivalent) and 50-mL centrifuge tubes (Nalgene, Ultratube, Thin
Wall 25 x 89 mm, #3410-2539).
6.3 Gas Chromatograph/Mass Spectrometer (GC/MS):
6.3.1 Gas Chromatograph--An analytical system complete with a
temperature-programmable gas chromatograph suitable for split/
splitless injection and all required accessories, including
syringes, analytical columns, and gases.
6.3.1.1 Column--30 m (or 60 m) x 0.32 mm ID (or 0.25 mm ID)
1m film thickness (or 0.25m film thickness)
silicone-coated fused-silica capillary column (J&W Scientific DB-5
or equivalent).
6.3.2 Mass Spectrometer--Capable of scanning from 35 to 500 amu
every 1 sec or less, using 70 volts (nominal) electron energy in the
electron impact ionization mode (Hewlett Packard 5970MS or
comparable).
6.3.3 GC/MS interface--the interface is a capillary-direct
interface from the GC to the MS.
6.3.4--Data system--A computer system must be interfaced to the
mass spectrometer. The system must allow the continuous acquisition
and storage on machine-readable media of all mass spectra obtained
throughout the duration of the chromatographic program. The computer
must have software that can search any GC/MS data file for ions of a
specific mass and that can plot such ion abundance versus retention
time or scan number. This type of plot is defined as an Extracted
Ion Current Profile (EIP). Software must also be available that
allows integrating the abundance in any total ion chromatogram (TIC)
or EIP between specified retention time or scan-number limits. It is
advisable that the most recent version of the EPA/NIST Mass Spectral
Library be available.
7.0 Reagents and Standards
7.1 Methylene chloride--Pesticide grade or equivalent. Use when
necessary for sample dilution.
7.2 Standards--Prepare from pure individual standard materials
or purchase as certified solutions. If compound purity is 96% or
greater, the weight may be used without correction to compute the
concentration of the standard.
7.2.1 Crude Oil Reference--Obtain a sample of a crude oil with
a known API gravity. This oil shall be used in the calibration
procedures.
7.2.2 Synthetic Base Fluid--Obtain a sample of clean internal
olefin (IO) Lab drilling fluid (as sent from the supplier--has not
been circulated downhole). This drilling fluid shall be used in the
calibration procedures.
7.2.3 Internal standard--Prepare a 0.01 g/mL solution of 1,3,5-
trichlorobenzene (TCB). Dissolve 1.0 g of TCB in methylene chloride
and dilute to volume in a 100-mL volumetric flask. Stopper, vortex,
and transfer the solution to a 150-mL bottle with PTFE-lined cap.
Label appropriately, and store at -5 deg.C to 20 deg.C. Mark the
level of the meniscus on the bottle to detect solvent loss.
7.2.4 GC/MS system performance test mix (SPTM) standards--The
SPTM standards shall contain octane, decane, dodecane, tetradecane,
tetradecene, toluene, ethylbenzene, 1,2,4-trimethylbenzene, 1-
methylnaphthalene and 1,3-dimethylnaphthalene. These compounds can
be purchased individually or obtained as a mixture (i.e. Supelco,
Catalog No. 4-7300). Prepare a high concentration of the SPTM
standard at 62.5 mg/mL in methylene chloride. Prepare a medium
concentration SPTM standard at 1.25 mg/mL by transferring 1.0 mL of
the 62.5 mg/mL solution into a 50 mL volumetric flask and diluting
to the mark with methylene chloride. Finally, prepare a low
concentration SPTM standard at 0.125 mg/mL by transferring 1.0 mL of
the 1.25 mg/mL solution into a 10-mL volumetric flask and diluting
to the mark with methylene chloride.
7.2.5 Crude oil/drilling fluid calibration standards--Prepare a
4-point crude oil/drilling fluid calibration at concentrations of 0%
(no spike--clean drilling fluid), 0.5%, 1.0%, and 2.0% by weight
according to the procedures outlined in this appendix using the
Reference Crude Oil:
7.2.5.1 Label 4 jars with the following identification: Jar 1--
0%Ref-IOLab, Jar 2--0.5%Ref-IOLab, Jar 3--1%Ref-IOLab, and Jar 4--
2%Ref-IOLab.
7.2.5.2 Weigh 4, 50-g aliquots of well mixed IO Lab drilling
fluid into each of the 4 jars.
7.2.5.3 Add Reference Oil at 0.5%, 1.0%, and 2.0% by weight to
jars 2, 3, and 4 respectively. Jar 1 shall not be spiked with
Reference Oil in order to retain a ``0%'' oil concentration.
7.2.5.4 Thoroughly mix the contents of each of the 4 jars,
using clean glass stirring rods.
7.2.5.5 Transfer (weigh) a 30-g aliquot from Jar 1 to a labeled
centrifuge tube. Centrifuge the aliquot for a minimum of 15 min at
approximately 15,000 rpm, in order to obtain a solids free
supernate. Weigh 0.5 g of the supernate directly into a tared and
appropriately labeled GC straight vial. Spike the 0.5-g supernate
with 500 L of the 0.01g/mL 1,3,5-trichlorobenzene internal
standard solution (see Section 7.2.3 of this appendix), cap with a
Teflon lined crimp cap, and vortex for ca. 10 sec.
7.2.5.6 Repeat step 7.2.5.5 except use an aliquot from Jar 2.
7.2.5.7 Repeat step 7.2.5.5 except use an aliquot from Jar 3.
7.2.5.8 Repeat step 7.2.5.5 except use an aliquot from Jar 4.
7.2.5.9 These 4 crude/oil drilling fluid calibration standards
are now used for qualitative and quantitative GC/MS analysis.
7.2.6 Precision and recovery standard (mid level crude oil/
drilling fluid calibration standard)--Prepare a mid point crude oil/
drilling fluid calibration using IO Lab drilling fluid and Reference
Oil at a concentration of 1.0% by weight. Prepare this standard
according to the procedures outlined in Section 7.2.5.1 through
7.2.5.5 of this appendix, with the exception that only ``Jar
[[Page 6904]]
3'' needs to be prepared. Remove and spike with internal standard,
as many 0.5-g aliquots as needed to complete the GC/MS analysis (see
Section 11.6 of this appendix--bracketing authentic samples every 12
hours with precision and recovery standard) and the initial
demonstration exercise described in Section 9.2 of this appendix.
7.2.7 Stability of standards
7.2.7.1 When not used, standards shall be stored in the dark,
at -5 to -20 deg.C in screw-capped vials with PTFE-lined lids.
Place a mark on the vial at the level of the solution so that
solvent loss by evaporation can be detected. Bring the vial to room
temperature prior to use.
7.2.7.2 Solutions used for quantitative purposes shall be
analyzed within 48 hours of preparation and on a monthly basis
thereafter for signs of degradation. A standard shall remain
acceptable if the peak area remains within 15% of the
area obtained in the initial analysis of the standard.
8.0 Sample Collection Preservation and Storage
8.1 Collect NAF and base fluid samples in 100- to 200-mL glass
bottles with PTFE- or aluminum foil lined caps.
8.2 Samples collected in the field shall be stored refrigerated
until time of preparation.
8.3 Sample and extract holding times for this method have not
yet been established. However, based on initial experience with the
method, samples should be analyzed within seven to ten days of
collection and extracts should be analyzed within seven days of
preparation.
8.4 After completion of GC/MS analysis, extracts shall be
refrigerated at 4 deg.C until further notification of sample
disposal.
9.0 Quality Control
9.1 Each laboratory that uses this method is required to
operate a formal quality assurance program (Reference 16.4). The
minimum requirements of this program shall consist of an initial
demonstration of laboratory capability, and ongoing analysis of
standards, and blanks as a test of continued performance, analyses
of spiked samples to assess accuracy and analysis of duplicates to
assess precision. Laboratory performance shall be compared to
established performance criteria to determine if the results of
analyses meet the performance characteristics of the method.
9.1.1 The analyst shall make an initial demonstration of the
ability to generate acceptable accuracy and precision with this
method. This ability shall be established as described in Section
9.2 of this appendix.
9.1.2 The analyst is permitted to modify this method to improve
separations or lower the cost of measurements, provided all
performance requirements are met. Each time a modification is made
to the method, the analyst is required to repeat the calibration
(Section 10.4 of this appendix) and to repeat the initial
demonstration procedure described in Section 9.2 of this appendix.
9.1.3 Analyses of blanks are required to demonstrate freedom
from contamination. The procedures and criteria for analysis of a
blank are described in Section 9.3 of this appendix.
9.1.4 Analysis of a matrix spike sample is required to
demonstrate method accuracy. The procedure and QC criteria for
spiking are described in Section 9.4 of this appendix.
9.1.5 Analysis of a duplicate field sample is required to
demonstrate method precision. The procedure and QC criteria for
duplicates are described in Section 9.5 of this appendix.
9.1.6 Analysis of a sample of the clean NAF(s) (as sent from
the supplier--i.e., has not been circulated downhole) used in the
drilling operations is required.
9.1.7 The laboratory shall, on an ongoing basis, demonstrate
through calibration verification and the analysis of the precision
and recovery standard (Section 7.2.6 of this appendix) that the
analysis system is in control. These procedures are described in
Section 11.6 of this appendix.
9.1.8 The laboratory shall maintain records to define the
quality of data that is generated.
9.2 Initial precision and accuracy--The initial precision and
recovery test shall be performed using the precision and recovery
standard (1% by weight Reference Oil in IO Lab drilling fluid). The
laboratory shall generate acceptable precision and recovery by
performing the following operations.
9.2.1 Prepare four separate aliquots of the precision and
recovery standard using the procedure outlined in Section 7.2.6 of
this appendix. Analyze these aliquots using the procedures outlined
in Section 11 of this appendix.
9.2.2 Using the results of the set of four analyses, compute
the average recovery (X) in weight percent and the standard
deviation of the recovery(s) for each sample.
9.2.3 If s and X meet the acceptance criteria of 80% to 110%,
system performance is acceptable and analysis of samples may begin.
If, however, s exceeds the precision limit or X falls outside the
range for accuracy, system performance is unacceptable. In this
event, review this method, correct the problem, and repeat the test.
9.2.4 Accuracy and precision--The average percent recovery (P)
and the standard deviation of the percent recovery (Sp) Express the
accuracy assessment as a percent recovery interval from P-
2Sp to P+2Sp. For example, if P=90% and
Sp=10% for four analyses of crude oil in NAF, the
accuracy interval is expressed as 70% to 110%. Update the accuracy
assessment on a regular basis.
9.3 Blanks--Rinse glassware and centrifuge tubes used in the
method with 30 mL of methylene chloride, remove a 0.5-g aliquot of
the solvent, spike it with the 500 L of the internal
standard solution (Section 7.2.3 of this appendix) and analyze a 1-
L aliquot of the blank sample using the procedure in
Section 11 of this appendix. Compute results per Section 12 of this
appendix.
9.4 Matrix spike sample--Prepare a matrix spike sample
according to procedure outlined in Section 7.2.6 of this appendix.
Analyze the sample and calculate the concentration (% oil) in the
drilling fluid and % recovery of oil from the spiked drilling fluid
using the methods described in Sections 11 and 12 of this appendix.
9.5 Duplicates--A duplicate field sample shall be prepared
according to procedures outlined in Section 7.3 of this appendix and
analyzed according to Section 11 of this appendix. The relative
percent difference (RPD) of the calculated concentrations shall be
less than 15%.
9.5.1 Analyze each of the duplicates per the procedure in
Section 11 of this appendix and compute the results per Section 12
of this appendix.
9.5.2 Calculate the relative percent difference (RPD) between
the two results per the following equation:
RPD = [D1 - D2]/[(D1 +
D2)/2] x 100 [1]
where:
D1 = Concentration of crude oil in the sample; and
D2 = Concentration of crude oil in the duplicate sample.
9.5.3 If the RPD criteria are not met, the analytical system
shall be judged to be out of control, and the problem must be
immediately identified and corrected, and the sample batch re-
analyzed.
9.6 Prepare the clean NAF sample according to procedures
outlined in Section 7.3 of this appendix. Ultimately the oil-
equivalent concentration from the TIC or EIP signal measured in the
clean NAF sample shall be subtracted from the corresponding
authentic field samples in order to calculate the true contaminant
concentration (% oil) in the field samples (see Section 12 of this
appendix).
9.7 The specifications contained in this method can be met if
the apparatus used is calibrated properly, and maintained in a
calibrated state. The standards used for initial precision and
recovery (Section 9.2 of this appendix) and ongoing precision and
recovery (Section 11.6 of this appendix) shall be identical, so that
the most precise results will be obtained. The GC/MS instrument will
provide the most reproducible results if dedicated to the setting
and conditions required for the analyses given in this method.
9.8 Depending on specific program requirements, field
replicates and field spikes of crude oil into samples may be
required when this method is used to assess the precision and
accuracy of the sampling and sample transporting techniques.
10.0 Calibration
10.1 Establish gas chromatographic/mass spectrometer operating
conditions given in Table 1 of this appendix. Perform the GC/MS
system hardware-tune as outlined by the manufacture. The gas
chromatograph shall be calibrated using the internal standard
technique.
Note: Because each GC is slightly different, it may be necessary
to adjust the operating conditions (carrier gas flow rate and column
temperature and temperature program) slightly until the retention
times in Table 2 of this appendix are met.
Table 1.--Gas Chromatograph/Mass Spectrometer (GC/MS) Operation
Conditions
------------------------------------------------------------------------
Parameter Setting
------------------------------------------------------------------------
Injection pot............................. 280 deg.C
[[Page 6905]]
Transfer line............................. 280 deg.C
Detector.................................. 280 deg.C
Initial Temperature....................... 50 deg.C
Initial Time.............................. 5 minutes
Ramp...................................... 50 to 300 deg.C @ 5 deg.C
per minute
Final Temperature......................... 300 deg.C
Final Hold................................ 20 minutes or until all
peaks have eluted
Carrier Gas............................... Helium
Flow rate................................. As required for standard
operation
Split ratio............................... As required to meet
performance criteria
(~1:100)
Mass range................................ 35 to 600 amu
------------------------------------------------------------------------
Table 2.--Approximate Retention Time for Compounds
------------------------------------------------------------------------
Approximate
retention
Compound time
(minutes)
------------------------------------------------------------------------
Toluene.................................................... 5.6
Octane, n-C8............................................... 7.2
Ethylbenzene............................................... 10.3
1,2,4-Trimethylbenzene..................................... 16.0
Decane, -C10............................................... 16.1
TCB (Internal Standard).................................... 21.3
Dodecane, -C12............................................. 22.9
1-Methylnaphthalene........................................ 26.7
1-Tetradecene.............................................. 28.4
Tetradecane, -C14.......................................... 28.7
1,3-Dimethylnaphthalene.................................... 29.7
------------------------------------------------------------------------
10.2 Internal standard calibration procedure--1,3,5-
trichlorobenzene (TCB) has been shown to be free of interferences
from diesel and crude oils and is a suitable internal standard.
10.3 The system performance test mix standards prepared in
Section 7.2.4 of this appendix shall be used to establish retention
times and establish qualitative detection limits.
10.3.1 Spike a 500-mL aliquot of the 1.25 mg/mL SPTM standard
with 500 L of the TCB internal standard solution.
10.3.2 Inject 1.0 L of this spiked SPTM standard onto
the GC/MS in order to demonstrate proper retention times. For the
GC/MS used in the development of this method, the ten compounds in
the mixture had typical retention times shown in Table 2 of this
appendix. Extracted ion scans for m/z 91 and 105 showed a maximum
abundance of 400,000.
10.3.3 Spike a 500-mL aliquot of the 0.125 mg/mL SPTM standard
with 500 L of the TCB internal standard solution.
10.3.4 Inject 1.0 L of this spiked SPTM standard onto
the GC/MS to monitor detectable levels. For the GC/MS used in the
development of this test, all ten compounds showed a minimum peak
height of three times signal to noise. Extracted ion scans for m/z
91 and 105 showed a maximum abundance of 40,000.
10.4 GC/MS crude oil/drilling fluid calibration--There are two
methods of quantification: Total Area Integration (C8-
C13) and EIP Area Integration using m/z's 91 and 105. The
Total Area Integration method should be used as the primary
technique for quantifying crude oil in NAFs. The EIP Area
Integration method should be used as a confirmatory technique for
NAFs. However, the EIP Area Integration method shall be used as the
primary method for quantifying oil in enhanced mineral oil (EMO)
based drilling fluid. Inject 1.0 L of each of the four
crude oil/drilling fluid calibration standards prepared in Section
7.2.5 of this appendix into the GC/MS. The internal standard should
elute approximately 21-22 minutes after injection. For the GC/MS
used in the development of this method, the internal standard peak
was (35 to 40)% of full scale at an abundance of about 3.5e+07.
10.4.1 Total Area Integration Method--For each of the four
calibration standards obtain the following: Using a straight
baseline integration technique, obtain the total ion chromatogram
(TIC) area from C8 to C13. Obtain the TIC area
of the internal standard (TCB). Subtract the TCB area from the
C8-C13 area to obtain the true C8-
C13 area. Using the C8-C13 and TCB
areas, and known internal standard concentration, generate a linear
regression calibration using the internal standard method. The
r2 value for the linear regression curve shall be greater
than or equal to 0.998. Some synthetic fluids might have peaks that
elute in the window and would interfere with the analysis. In this
case the integration window can be shifted to other areas of scan
where there are no interfering peaks from the synthetic base fluid.
10.4.2 EIP Area Integration--For each of the four calibration
standards generate Extracted Ion Profiles (EIPs) for m/z 91 and 105.
Using straight baseline integration techniques, obtain the following
EIP areas:
10.4.2.1 For m/z 91 integrate the area under the curve from
approximately 9 minutes to 21-22 minutes, just prior to but not
including the internal standard.
10.4.2.2 For m/z 105 integrate the area under the curve from
approximately 10.5 minutes to 26.5 minutes.
10.4.2.3 Obtain the internal standard area from the TCB in each
of the four calibration standards, using m/z 180.
10.4.2.4 Using the EIP areas for TCB, m/z 91 and m/z105, and
the known concentration of internal standard, generate linear
regression calibration curves for the target ions 91 and 105 using
the internal standard method. The r2 value for each of
the EIP linear regression curves shall be greater than or equal to
0.998.
10.4.2.5 Some base fluids might produce a background level that
would show up on the extracted ion profiles, but there should not be
any real peaks (signal to noise ratio of 1:3) from the clean base
fluids.
11.0 Procedure
11.1 Sample Preparation--
11.1.1 Mix the authentic field sample (drilling fluid) well.
Transfer (weigh) a 30-g aliquot of the sample to a labeled
centrifuge tube.
11.1.2 Centrifuge the aliquot for a minimum of 15 min at
approximately 15,000 rpm, in order to obtain a solids free
supernate.
11.1.3 Weigh 0.5 g of the supernate directly into a tared and
appropriately labeled GC straight vial.
11.1.4 Spike the 0.5-g supernate with 500 L of the
0.01g/mL 1,3,5-trichlorobenzene internal standard solution (see
Section 7.2.3 of this appendix), cap with a Teflon lined crimp cap,
and vortex for ca. 10 sec.
11.1.5 The sample is ready for GC/MS analysis.
11.2 Gas Chromatography.
Table 1 of this appendix summarizes the recommended operating
conditions for the GC/MS. Retention times for the n-alkanes obtained
under these conditions are given in Table 2 of this appendix. Other
columns, chromatographic conditions, or detectors may be used if
initial precision and accuracy requirements (Section 9.2 of this
appendix) are met. The system shall be calibrated according to the
procedures outlined in Section 10 of this appendix, and verified
every 12 hours according to Section 11.6 of this appendix.
11.2.1 Samples shall be prepared (extracted) in a batch of no
more than 20 samples. The batch shall consist of 20 authentic
samples, 1 blank (Section 9.3 of this appendix), 1 matrix spike
sample (9.4), and 1 duplicate field sample (9.5), and a prepared
sample of the corresponding clean NAF used in the drilling process.
11.2.2 An analytical sequence shall be analyzed on the GC/MS
where the 3 SPTM standards (Section 7.2.4 of this appendix)
containing internal standard are analyzed first, followed by
analysis of the four GC/MS crude oil/drilling fluid calibration
standards (Section 7.2.5 of this appendix), analysis of the blank,
matrix spike sample, the duplicate sample, the clean NAF sample,
followed by the authentic samples.
11.2.3 Samples requiring dilution due to excessive signal shall
be diluted using methylene chloride.
11.2.4 Inject 1.0 L of the test sample or standard
into the GC, using the conditions in Table 1 of this appendix.
11.2.5 Begin data collection and the temperature program at the
time of injection.
11.2.6 Obtain a TIC and EIP fingerprint scans of the sample
(Table 3 of this appendix).
11.2.7 If the area of the C8 to C13 peaks
exceeds the calibration range of the system, dilute a fresh aliquot
of the test sample weighing 0.50-g and re-analyze.
11.2.8 Determine the C8 to C13 TIC area,
the TCB internal standard area, and the areas for the m/z 91 and 105
EIPs. These shall be used in the calculation of oil concentration in
the samples (see Section 12 of this appendix).
[[Page 6906]]
Table 3.--Recommended Ion Mass Numbers
------------------------------------------------------------------------
Corresponding Typical rentention
Selected ion mass numbers aromatic compounds time (minutes)
------------------------------------------------------------------------
91.............................. Methylbenzene..... 6.0
Ethylbenzene...... 10.3
1,4- 10.9
Dimethylbenzene.
1,3- 10.9
Dimethylbenzene.
1,2- 11.9
Dimethylbenzene.
105............................. 1,3,5- 15.1
Trimethylbenzene.
1,2,4- 16.0
Trimethylbenzene.
1,2,3- 17.4
Trimethylbenzene.
156............................. 2,6- 28.9
Dimethylnaphthale
ne.
1,2- 29.4
Dimethylnaphthale
ne.
1,3- 29.7
Dimethylnaphthale
ne.
------------------------------------------------------------------------
11.2.9 Observe the presence of peaks in the EIPs that would
confirm the presence of any target aromatic compounds. Using the EIP
areas and EIP linear regression calibrations compare the abundance
of the aromatic peaks, and if appropriate, determine approximate
crude oil contamination in the sample for each of the target ions.
11.3 Qualitative Identification--See Section 17 of this
appendix for schematic flowchart.
11.3.1 Qualitative identification shall be accomplished by
comparison of the TIC and EIP area data from an authentic sample to
the TIC and EIP area data from the calibration standards (Section
12.4 of this appendix). Crude oil shall be identified by the
presence of C10 to C13 n-alkanes and
corresponding target aromatics.
11.3.2 Using the calibration data, establish the identity of
the C8 to C13 peaks in the chromatogram of the
sample. Using the calibration data, establish the identity of any
target aromatics present on the extracted ion scans.
11.3.3 Crude oil is not present in a detectable amount in the
sample if there are no target aromatics seen on the extracted ion
scans. The experience of the analyst shall weigh heavily in the
determination of the presence of peaks at a signal-to-noise ratio of
3 or greater.
11.3.4 If the chromatogram shows n-alkanes from C8
to C13 and target aromatics to be present, contamination
by crude oil or diesel shall be suspected and quantitative analysis
shall be determined. If there are no n-alkanes present that are not
seen on the blank, and no target aromatics are seen, the sample can
be considered to be free of contamination.
11.4 Quantitative Identification--
11.4.1 Determine the area of the peaks from C8 to
C13 as outlined in the calibration section (10.4.1 of
this appendix). If the area of the peaks for the sample is greater
than that for the clean NAF (base fluid) use the crude oil/drilling
fluid calibration TIC linear regression curve to determine
approximate crude oil contamination.
11.4.2 Using the EIPs outlined in Section 10.4.2 of this
appendix, determine the presence of any target aromatics. Using the
integration techniques outlined in Section 10.4.2 of this appendix,
obtain the EIP areas for m/z 91 and 105. Use the crude oil/drilling
fluid calibration EIP linear regression curves to determine
approximate crude oil contamination.
11.5 Complex Samples--
11.5.1 The most common interferences in the determination of
crude oil can be from mineral oil, diesel oil, and proprietary
additives in drilling fluids.
11.5.2 Mineral oil can typically be identified by its lower
target aromatic content, and narrow range of strong peaks.
11.5.3 Diesel oil can typically be identified by low amounts of
n-alkanes from C7 to C9, and the absence of n-
alkanes greater than C25.
11.5.4 Crude oils can usually be distinguished by the presence
of high aromatics, increased intensities of C8 to
C13 peaks, and/ or the presence of higher hydrocarbons of
C25 and greater (which may be difficult to see in some
synthetic fluids at low contamination levels).
11.5.4.1 Oil condensates from gas wells are low in molecular
weight and will normally produce strong chromatographic peaks in the
C8-C13 range. If a sample of the gas
condensate crude oil from the formation is available, the oil can be
distinguished from other potential sources of contamination by using
it to prepare a calibration standard.
11.5.4.2 Asphaltene crude oils with API gravity 20 may not
produce chromatographic peaks strong enough to show contamination at
levels of the calibration. Extracted ion peaks should be easier to
see than increased intensities for the C8 to
C13 peaks. If a sample of asphaltene crude from the
formation is available, a calibration standard shall be prepared.
11.6 System and Laboratory Performance--
11.6.1 At the beginning of each 8-hour shift during which
analyses are performed, GC crude oil/drilling fluid calibration and
system performance test mixes shall be verified. For these tests,
analysis of the medium-level calibration standard (1-% Reference Oil
in IO Lab drilling fluid, and 1.25 mg/mL SPTM with internal
standard) shall be used to verify all performance criteria.
Adjustments and/or re-calibration (per Section 10 of this appendix)
shall be performed until all performance criteria are met. Only
after all performance criteria are met may samples and blanks be
analyzed.
11.6.2 Inject 1.0 L of the medium-level GC/MS crude
oil/drilling fluid calibration standard into the GC instrument
according to the procedures in Section 11.2 of this appendix. Verify
that the linear regression curves for both TIC area and EIP areas
are still valid using this continuing calibration standard.
11.6.3 After this analysis is complete, inject 1.0 L
of the 1.25 mg/mL SPTM (containing internal standard) into the GC
instrument and verify the proper retention times are met (see Table
2 of this appendix).
11.6.4 Retention times--Retention time of the internal
standard. The absolute retention time of the TCB internal standard
shall be within the range 21.0 0.5 minutes. Relative
retention times of the n-alkanes: The retention times of the n-
alkanes relative to the TCB internal standard shall be similar to
those given in Table 2 of this appendix.
12.0 Calculations
The concentration of oil in NAFs drilling fluids shall be
computed relative to peak areas between C8 and
C13 (using the Total Area Integration method) or total
peak areas from extracted ion profiles (using the Extracted Ion
Profile Method). In either case, there is a measurable amount of
peak area, even in clean drilling fluid samples, due to spurious
peaks and electrometer ``noise'' that contributes to the total
signal measured using either of the quantification methods. In this
procedure, a correction for this signal is applied, using the blank
or clean sample correction technique described in American Society
for Testing Materials (ASTM) Method D-3328-90, Comparison of
Waterborne Oil by Gas Chromatography. In this method, the ``oil
equivalents'' measured in a blank sample by total area gas
chromatography are subtracted from that determined for a field
sample to arrive at the most accurate measure of oil residue in the
authentic sample.
12.1 Total Area Integration Method
12.1.1 Using C8 to C13 TIC area, the TCB
area in the clean NAF sample and the TIC linear regression curve,
compute the oil equivalent concentration of the C8 to
C13 retention time range in the clean NAF.
Note: The actual TIC area of the C8 to C13
is equal to the C8 to C13 area minus the area
of the TCB.
12.1.2 Using the corresponding information for the authentic
sample, compute the oil equivalent concentration of the
C8 to C13 retention time range in the
authentic sample.
12.1.3 Calculate the concentration (% oil) of oil in the sample
by subtracting the oil
[[Page 6907]]
equivalent concentration (% oil) found in the clean NAF from the oil
equivalent concentration (% oil) found in the authentic sample.
12.2 EIP Area Integration Method
12.2.1 Using either m/z 91 or 105 EIP areas, the TCB area in
the clean NAF sample, and the appropriate EIP linear regression
curve, compute the oil equivalent concentration of the in the clean
NAF.
12.2.2 Using the corresponding information for the authentic
sample, compute its oil equivalent concentration.
12.2.3 Calculate the concentration (% oil) of oil in the sample
by subtracting the oil equivalent concentration (% oil) found in the
clean NAF from the oil equivalent concentration (% oil) found in the
authentic sample.
13.0 Method Performance
13.1 Specification in this method are adopted from EPA Method
1663, Differentiation of Diesel and Crude Oil by GC/FID (Reference
16.5).
13.2 Single laboratory method performance using an Internal
Olefin (IO) drilling fluid fortified at 0.5% oil using a 35 API
gravity oil was:
Precision and accuracy 944%
Accuracy interval--86.3% to 102%
Relative percent difference in duplicate analysis--6.2%
14.0 Pollution Prevention
14.1 The solvent used in this method poses little threat to the
environment when recycled and managed properly.
15.0 Waste Management
15.1 It is the laboratory's responsibility to comply with all
federal, state, and local regulations governing waste management,
particularly the hazardous waste identification rules and land
disposal restriction, and to protect the air, water, and land by
minimizing and controlling all releases from fume hoods and bench
operations. Compliance with all sewage discharge permits and
regulations is also required.
15.2 All authentic samples (drilling fluids) failing the RPE
(fluorescence) test (indicated by the presence of fluorescence)
shall be retained and classified as contaminated samples. Treatment
and ultimate fate of these samples is not outlined in this SOP.
15.3 For further information on waste management, consult ``The
Waste Management Manual for Laboratory Personnel'', and ``Less is
Better: Laboratory Chemical Management for Waste Reduction'', both
available from the American Chemical Society's Department of
Government Relations and Science Policy, 1155 16th Street NW,
Washington, DC 20036.
16.0 References
16.1 Carcinogens--``Working With Carcinogens.'' Department of
Health, Education, and Welfare, Public Health Service, Centers for
Disease Control (available through National Technical Information
Systems, 5285 Port Royal Road, Springfield, VA 22161, document no.
PB-277256): August 1977.
16.2 ``OSHA Safety and Health Standards, General Industry [29
CFR 1910], Revised.'' Occupational Safety and Health Administration,
OSHA 2206. Washington, DC: January 1976.
16.3 ``Handbook of Analytical Quality Control in Water and
Wastewater Laboratories.'' USEPA, EMSSL-CI, EPA-600/4-79-019.
Cincinnati, OH: March 1979.
16.4 ``Method 1663, Differentiation of Diesel and Crude Oil by
GC/FID, Methods for the Determination of Diesel, Mineral, and Crude
Oils in Offshore Oil and Gas Industry Discharges, EPA 821-R-92-008,
Office of Water Engineering and Analysis Division, Washington, DC:
December 1992.
Appendix 6 to Subpart A of Part 435--Reverse Phase Extraction (RPE)
Method for Detection of Oil Contamination in Non-Aqueous Drilling
Fluids (NAF)
1.0 Scope and Application
1.1 This method is used for determination of crude or formation
oil, or other petroleum oil contamination, in non-aqueous drilling
fluids (NAFs).
1.2 This method is intended as a positive/negative test to
determine a presence of crude oil in NAF prior to discharging drill
cuttings from offshore production platforms.
1.3 This method is for use in the Environmental Protection
Agency's (EPA's) survey and monitoring programs under the Clean
Water Act, including monitoring of compliance with the Gulf of
Mexico NPDES General Permit for monitoring of oil contamination in
drilling fluids.
1.4 This method has been designed to show positive
contamination for 5% of representative crude oils at a concentration
of 0.1% in drilling fluid (vol/vol), 50% of representative crude
oils at a concentration of 0.5%, and 95% of representative crude
oils at a concentration of 1%.
1.5 Any modification of this method, beyond those expressly
permitted, shall be considered a major modification subject to
application and approval of alternate test procedures under 40 CFR
Parts 136.4 and 136.5.
1.6 Each laboratory that uses this method must demonstrate the
ability to generate acceptable results using the procedure in
Section 9.2 of this appendix.
2.0 Summary of Method
2.1 An aliquot of drilling fluid is extracted using isopropyl
alcohol.
2.2 The mixture is allowed to settle and then filtered to
separate out residual solids.
2.3 An aliquot of the filtered extract is charged onto a
reverse phase extraction (RPE) cartridge.
2.4 The cartridge is eluted with isopropyl alcohol.
2.5 Crude oil contaminates are retained on the cartridge and
their presence (or absence) is detected based on observed
fluorescence using a black light.
3.0 Definitions
3.1 A NAF is one in which the continuous phase is a water
immiscible fluid such as an oleaginous material (e.g., mineral oil,
enhance mineral oil, paraffinic oil, or synthetic material such as
olefins and vegetable esters).
4.0 Interferences
4.1 Solvents, reagents, glassware, and other sample-processing
hardware may yield artifacts that affect results. Specific selection
of reagents and purification of solvents may be required.
4.2 All materials used in the analysis shall be demonstrated to
be free from interferences under the conditions of analysis by
running laboratory reagent blanks as described in Section 9.5 of
this appendix.
5.0 Safety
5.1 The toxicity or carcinogenicity of each reagent used in
this method has not been precisely determined; however, each
chemical shall be treated as a potential health hazard. Exposure to
these chemicals should be reduced to the lowest possible level.
Material Safety Data Sheets (MSDSs) shall be available for all
reagents.
5.2 Isopropyl alcohol is flammable and should be used in a
well-ventilated area.
5.3 Unknown samples may contain high concentration of volatile
toxic compounds. Sample containers should be opened in a hood and
handled with gloves to prevent exposure. In addition, all sample
preparation should be conducted in a well-ventilated area to limit
the potential exposure to harmful contaminants. Drilling fluid
samples should be handled with the same precautions used in the
drilling fluid handling areas of the drilling rig.
5.4 This method does not address all safety issues associated
with its use. The laboratory is responsible for maintaining a safe
work environment and a current awareness file of OSHA regulations
regarding the safe handling of the chemicals specified in this
method. A reference file of material safety data sheets (MSDSs)
shall be available to all personnel involved in these analyses.
Additional information on laboratory safety can be found in
References 16.1-16.2.
6.0 Equipment and Supplies
Note: Brand names, suppliers, and part numbers are for
illustrative purposes only. No endorsement is implied. Equivalent
performance may be achieved using apparatus and materials other than
those specified here, but demonstration of equivalent performance
that meets the requirements of this method is the responsibility of
the laboratory.
6.1 Sampling equipment.
6.1.1 Sample collection bottles/jars--New, pre-cleaned bottles/
jars, lot-certified to be free of artifacts. Glass preferable,
plastic acceptable, wide mouth approximately 1-L, with Teflon-lined
screw cap.
6.2 Equipment for glassware cleaning.
6.2.1 Laboratory sink.
6.2.2 Oven--Capable of maintaining a temperature within
5 deg.C in the range of 100-250 deg.C.
6.3 Equipment for sample extraction.
6.3.1 Vials--Glass, 25 mL and 4 mL, with Teflon-lined screw
caps, baked at 200-250 deg.C for 1-h minimum prior to use.
6.3.2 Gas-tight syringes--Glass, various sizes, 0.5 mL to 2.5
mL (if spiking of drilling fluids with oils is to occur).
6.3.3 Auto pipetters--various sizes, 0.1 mL, 0.5 mL, 1 to 5 mL
delivery, and 10 mL
[[Page 6908]]
delivery, with appropriate size disposable pipette tips, calibrated
to within 0.5%.
6.3.4 Glass stirring rod.
6.3.5 Vortex mixer.
6.3.6 Disposable syringes--Plastic, 5 mL.
6.3.7 Teflon syringe filter, 25-mm, 0.45m pore size--
Acrodisc CR Teflon (or equivalent).
6.3.8 Reverse Phase Extraction C18 Cartridge--Waters
Sep-PakPlus, C18 Cartridge, 360 mg of sorbent
(or equivalent).
6.3.9 SPE vacuum manifold--Supelco Brand, 12 unit (or
equivalent). Used as support for cartridge/syringe assembly only.
Vacuum apparatus not required.
6.4 Equipment for fluorescence detection.
6.4.1 Black light--UV Lamp, Model UVG 11, Mineral Light Lamp,
Shortwave 254 nm, or Longwave 365 nm, 15 volts, 60 Hz, 0.16 amps (or
equivalent).
6.4.2 Black box--cartridge viewing area. A commercially
available ultraviolet viewing cabinet with viewing lamp, or
alternatively, a cardboard box or equivalent, approximately
14" x 7.5" x 7.5" in size and painted flat black inside. Lamp
positioned in fitted and sealed slot in center on top of box. Sample
cartridges sit in a tray, ca. 6" from lamp. Cardboard flaps cut on
top panel and side of front panel for sample viewing and sample
cartridge introduction, respectively.
6.4.3 Viewing platform for cartridges. Simple support (hand
made vial tray--black in color) for cartridges so that they do not
move during the fluorescence testing.
7.0 Reagents and Standards
7.1 Isopropyl alcohol--99% purity.
7.2 NAF--Appropriate NAF as sent from the supplier (has not
been circulated downhole). Use the clean NAF corresponding to the
NAF being used in the current drilling operation.
7.3 Standard crude oil--NIST SRM 1582 petroleum crude oil.
8.0 Sample Collection, Preservation, and Storage
8.1 Collect approximately one liter of representative sample
(NAF, which has been circulated downhole) in a glass bottle or jar.
Cover with a Teflon lined cap. To allow for a potential need to re-
analyze and/or re-process the sample, it is recommended that a
second sample aliquot be collected.
8.2 Label the sample appropriately.
8.3 All samples must be refrigerated at 0-4 deg.C from the
time of collection until extraction (40 CFR Part 136, Table II).
8.4 All samples must be analyzed within 28 days of the date and
time of collection (40 CFR Part 136, Table II).
9.0 Quality Control
9.1 Each laboratory that uses this method is required to
operate a formal quality assurance program (Reference 16.3). The
minimum requirements of this program consist of an initial
demonstration of laboratory capability, and ongoing analyses of
blanks and spiked duplicates to assess accuracy and precision and to
demonstrate continued performance. Each field sample is analyzed in
duplicate to demonstrate representativeness.
9.1.1 The analyst shall make an initial demonstration of the
ability to generate acceptable accuracy and precision with this
method. This ability is established as described in Section 9.2 of
this appendix.
9.1.2 Preparation and analysis of a set of spiked duplicate
samples to document accuracy and precision. The procedure for the
preparation and analysis of these samples is described in Section
9.4 of this appendix.
9.1.3 Analyses of laboratory reagent blanks are required to
demonstrate freedom from contamination. The procedure and criteria
for preparation and analysis of a reagent blank are described in
Section 9.5 of this appendix.
9.1.4 The laboratory shall maintain records to define the
quality of the data that is generated.
9.1.5 Accompanying QC for the determination of oil in NAF is
required per analytical batch. An analytical batch is a set of
samples extracted at the same time, to a maximum of 10 samples. Each
analytical batch of 10 or fewer samples must be accompanied by a
laboratory reagent blank (Section 9.5 of this appendix),
corresponding NAF reference blanks (Section 9.6 of this appendix), a
set of spiked duplicate samples blank (Section 9.4 of this
appendix), and duplicate analysis of each field sample. If greater
than 10 samples are to be extracted at one time, the samples must be
separated into analytical batches of 10 or fewer samples.
9.2 Initial demonstration of laboratory capability. To
demonstrate the capability to perform the test, the analyst shall
analyze two representative unused drilling fluids (e.g., internal
olefin-based drilling fluid, vegetable ester-based drilling fluid),
each prepared separately containing 0.1%, 1%, and 2% or a
representative oil. Each drilling fluid/concentration combination
shall be analyzed 10 times, and successful demonstration will yield
the following average results for the data set:
0.1% oil--Detected in 20% of samples
1% oil--Detected in >75% of samples
2% oil--Detected in 90% of samples
9.3 Sample duplicates.
9.3.1 The laboratory shall prepare and analyze (Section 11.2
and 11.4 of this appendix) each authentic sample in duplicate, from
a given sampling site or, if for compliance monitoring, from a given
discharge.
9.3.2 The duplicate samples must be compared versus the
prepared corresponding NAF blank.
9.3.3 Prepare and analyze the duplicate samples according to
procedures outlined in Section 11 of this appendix.
9.3.4 The results of the duplicate analyses are acceptable if
each of the results give the same response (fluorescence or no
fluorescence). If the results are different, sample non-homogenicity
issues may be a concern. Prepare the samples again, ensuring a well-
mixed sample prior to extraction. Analyze the samples once again.
9.3.5 If different results are obtained for the duplicate a
second time, the analytical system is judged to be out of control
and the problem shall be identified and corrected, and the samples
re-analyzed.
9.4 Spiked duplicates--Laboratory prepared spiked duplicates
are analyzed to demonstrate acceptable accuracy and precision.
9.4.1 Preparation and analysis of a set of spiked duplicate
samples with each set of no more than 10 field samples is required
to demonstrate method accuracy and precision and to monitor matrix
interferences (interferences caused by the sample matrix). A field
NAF sample expected to contain less than 0.5% crude oil (and
documented to not fluoresce as part of the sample batch analysis)
shall be spiked with 1% (by volume) of suitable reference crude oil
and analyzed as field samples, as described in Section 11 of this
appendix. If no low-level drilling fluid is available, then the
unused NAF can be used as the drilling fluid sample.
9.5 Laboratory reagent blanks--Laboratory reagent blanks are
analyzed to demonstrate freedom from contamination.
9.5.1 A reagent blank is prepared by passing 4 mL of the
isopropyl alcohol through a Teflon syringe filter and collecting the
filtrate in a 4-mL glass vial. A Sep Pak C18
cartridge is then preconditioned with 3 mL of isopropyl alcohol. A
0.5-mL aliquot of the filtered isopropyl alcohol is added to the
syringe barrel along with 3.0 mL of isopropyl alcohol. The solvent
is passed through the preconditioned Sep Pak cartridge. An
additional 2-mL of isopropyl alcohol is eluted through the
cartridge. The cartridge is now considered the ``reagent blank''
cartridge and is ready for viewing (analysis). Check the reagent
blank cartridge under the black light for fluorescence. If the
isopropyl alcohol and filter are clean, no fluorescence will be
observed.
9.5.2 If fluorescence is detected in the reagent blank
cartridge, analysis of the samples is halted until the source of
contamination is eliminated and a prepared reagent blank shows no
fluorescence under a black light. All samples shall be associated
with an uncontaminated method blank before the results may be
reported for regulatory compliance purposes.
9.6 NAF reference blanks--NAF reference blanks are prepared
from the NAFs sent from the supplier (NAF that has not been
circulated downhole) and used as the reference when viewing the
fluorescence of the test samples.
9.6.1 A NAF reference blank is prepared identically to the
authentic samples. Place a 0.1 mL aliquot of the ``clean'' NAF into
a 25-mL glass vial. Add 10 mL of isopropyl alcohol to the vial. Cap
the vial. Vortex the vial for approximately 10 sec. Allow the solids
to settle for approximately 15 minutes. Using a 5-mL syringe, draw
up 4 mL of the extract and filter it through a PTFE syringe filter,
collecting the filtrate in a 4-mL glass vial. Precondition a Sep
Pak C18 cartridge with 3 mL of isopropyl
alcohol. Add a 0.5-mL aliquot of the filtered extract to the syringe
barrel along with 3.0 mL of isopropyl alcohol. Pass the extract and
solvent through the preconditioned Sep Pak cartridge. Pass
an additional 2-mL of isopropyl alcohol through the cartridge. The
cartridge is now considered the NAF blank cartridge and is ready for
viewing (analysis). This cartridge is used as the reference
cartridge for determining the absence or presence of fluorescence in
all authentic drilling fluid
[[Page 6909]]
samples that originate from the same NAF. That is, the specific NAF
reference blank cartridge is put under the black light along with a
prepared cartridge of an authentic sample originating from the same
NAF material. The fluorescence or absence of fluorescence in the
authentic sample cartridge is determined relative to the NAF
reference cartridge.
9.6.2 Positive control solution, equivalent to 1% crude oil
contaminated mud extract, is prepared by dissolving 87 mg of
standard crude oil into 10.00 mL of methylene chloride. Then mix 40
L of this solution into 10.00 mL of IPA. Transfer 0.5 mL of
this solution into a preconditioned C18 cartridge, followed by 2 ml
of IPA.
10.0 Calibration and Standardization
10.1 Calibration and standardization methods are not employed
for this procedure.
11.0 Procedure
This method is a screening-level test. Precise and accurate
results can be obtained only by strict adherence to all details.
11.1 Preparation of the analytical batch.
11.1.1 Bring the analytical batch of samples to room
temperature.
11.1.2 Using a large glass stirring rod, mix the authentic
sample thoroughly.
11.1.3 Using a large glass stirring rod, mix the clean NAF
(sent from the supplier) thoroughly.
11.2 Extraction.
11.2.1 Using an automatic positive displacement pipetter and a
disposable pipette tip transfer 0.1-mL of the authentic sample into
a 25-mL vial.
11.2.2 Using an automatic pipetter and a disposable pipette tip
dispense a 10-mL aliquot of solvent grade isopropyl alcohol (IPA)
into the 25 mL vial.
11.2.3 Cap the vial and vortex the vial for ca. 10-15 seconds.
11.2.4 Let the sample extract stand for approximately 5
minutes, allowing the solids to separate.
11.2.5 Using a 5-mL disposable plastic syringe remove 4 mL of
the extract from the 25-mL vial.
11.2.6 Filter 4 mL of extract through a Teflon syringe filter
(25-mm diameter, 0.45 m pore size), collecting the filtrate
in a labeled 4-mL vial.
11.2.7 Dispose of the PFTE syringe filter.
11.2.8 Using a black permanent marker, label a Sep
Pak C18 cartridge with the sample
identification.
11.2.9 Place the labeled Sep Pak C18
cartridge onto the head of a SPE vacuum manifold.
11.2.10 Using a 5-mL disposable plastic syringe, draw up
exactly 3-mL (air free) of isopropyl alcohol.
11.2.11 Attach the syringe tip to the top of the C18
cartridge.
11.2.12 Condition the C18 cartridge with the 3-mL of
isopropyl alcohol by depressing the plunger slowly.
Note: Depress the plunger just to the point when no liquid
remains in the syringe barrel. Do not force air through the
cartridge. Collect the eluate in a waste vial.
11.2.13 Remove the syringe temporarily from the top of the
cartridge, then remove the plunger, and finally reattach the syringe
barrel to the top of the C18 cartridge.
11.2.14 Using automatic pipetters and disposable pipette tips,
transfer 0.5 mL of the filtered extract into the syringe barrel,
followed by a 3.0-mL transfer of isopropyl alcohol to the syringe
barrel.
11.2.15 Insert the plunger and slowly depress it to pass only
the extract and solvent through the preconditioned C18
cartridge.
Note: Depress the plunger just to the point when no liquid
remains in the syringe barrel. Do not force air through the
cartridge. Collect the eluate in a waste vial.
11.2.16 Remove the syringe temporarily from the top of the
cartridge, then remove the plunger, and finally reattach the syringe
barrel to the top of the C18 cartridge.
11.2.17 Using an automatic pipetter and disposable pipette tip,
transfer 2.0 mL of isopropyl alcohol to the syringe barrel.
11.2.18 Insert the plunger and slowly depress it to pass the
solvent through the C18 cartridge.
Note: Depress the plunger just to the point when no liquid
remains in the syringe barrel. Do not force air through the
cartridge. Collect the eluate in a waste vial.
11.2.19 Remove the syringe and labeled C18 cartridge
from the top of the SPE vacuum manifold.
11.2.20 Prepare a reagent blank according to the procedures
outlined in Section 9.5 of this appendix.
11.2.21 Prepare the necessary NAF reference blanks for each
type of NAF encountered in the field samples according to the
procedures outlined in Section 9.6 of this appendix.
11.2.22 Prepare the positive control (1% crude oil equivalent)
according to Section 9.6.2 of this appendix.
11.3 Reagent blank fluorescence testing.
11.3.1 Place the reagent blank cartridge in a black box, under
a black light.
11.3.2 Determine the presence or absence of fluorescence for
the reagent blank cartridge. If fluorescence is detected in the
blank, analysis of the samples is halted until the source of
contamination is eliminated and a prepared reagent blank shows no
fluorescence under a black light. All samples must be associated
with an uncontaminated method blank before the results may be
reported for regulatory compliance purposes.
11.4 Sample fluorescence testing.
11.4.1 Place the respective NAF reference blank (Section 9.6 of
this appendix) onto the tray inside the black box.
11.4.2 Place the authentic field sample cartridge (derived from
the same NAF as the NAF reference blank) onto the tray, adjacent and
to the right of the NAF reference blank.
11.4.3 Turn on the black light.
11.4.4 Compare the fluorescence of the sample cartridge with
that of the negative control cartridge (NAF blank, Section 9.6.1 of
this appendix) and positive control cartridge (1% crude oil
equivalent, Section 9.6.2 of this appendix).
11.4.5 If the fluorescence of the sample cartridge is equal to
or brighter than the positive control cartridge (1% crude oil
equivalent, Section 9.6.2 of this appendix), the sample is
considered contaminated. Otherwise, the sample is clean.
12.0 Data Analysis and Calculations
Specific data analysis techniques and calculations are not
performed in this SOP.
13.0 Method Performance
This method was validated through a single laboratory study,
conducted with rigorous statistical experimental design and
interpretation (Reference 16.4).
14.0 Pollution Prevention
14.1 The solvent used in this method poses little threat to the
environment when recycled and managed properly.
15.0 Waste Management
15.1 It is the laboratory's responsibility to comply with all
Federal, State, and local regulations governing waste management,
particularly the hazardous waste identification rules and land
disposal restriction, and to protect the air, water, and land by
minimizing and controlling all releases from bench operations.
Compliance with all sewage discharge permits and regulations is also
required.
15.2 All authentic samples (drilling fluids) failing the
fluorescence test (indicated by the presence of fluorescence) shall
be retained and classified as contaminated samples. Treatment and
ultimate fate of these samples is not outlined in this SOP.
15.3 For further information on waste management, consult ``The
Waste Management Manual for Laboratory Personnel,'' and ``Less is
Better: Laboratory Chemical Management for Waste Reduction,'' both
available from the American Chemical Society's Department of
Government Relations and Science Policy, 1155 16th Street, NW,
Washington, DC 20036.
16.0 References
16.1 ``Carcinogen--Working with Carcinogens,'' Department of
Health, Education, and Welfare, Public Health Service, Center for
Disease Control, National Institute for Occupational Safety and
Health, Publication No. 77-206, August 1977.
16.2 ``OSHA Safety and Health Standards, General Industry,''
(29 CFR 1910), Occupational Safety and Health Administration, OSHA
2206 (Revised, January 1976).
16.3 ``Handbook of Analytical Quality Control in Water and
Wastewater Laboratories,'' USEPA, EMSL-Ci, Cincinnati, OH 45268,
EPA-600/4-79-019, March 1979.
16.4 Report of the Laboratory Evaluation of Static Sheen Test
Replacements--Reverse Phase Extraction (RPE) Method for Detecting
Oil Contamination in Synthetic Based Mud (SBM). October 1998.
Available from API, 1220 L Street, NW, Washington, DC 20005-4070,
202-682-8000.
Appendix 7 to Subpart A of Part 435--API Recommended Practice 13B-2
1. Description
a. This procedure is specifically intended to measure the amount
of non-aqueous drilling fluid (NAF) base fluid from cuttings
generated during a drilling operation. This procedure is a retort
test which measures all oily material (NAF base fluid) and water
released from a cuttings sample when heated
[[Page 6910]]
in a calibrated and properly operating ``Retort'' instrument.
b. In this retort test a known mass of cuttings is heated in the
retort chamber to vaporize the liquids associated with the sample.
The NAF base fluid and water vapors are then condensed, collected,
and measured in a precision graduated receiver.
Note: Obtaining a representative sample requires special
attention to the details of sample handling (e.g., location, method,
frequency). See Addendum A and B for minimum requirements for
collecting representative samples. Additional sampling procedures in
a given area may be specified by the NPDES permit controlling
authority.
2. Equipment
a. Retort instrument--The recommended retort instrument has a
50-cm3 volume with an external heating jacket.
Retort Specifications:
1. Retort assembly--retort body, cup and lid.
(a) Material: 303 stainless steel or equivalent.
(b) Volume: Retort cup with lid.
Cup Volume: 50-cm3.
Precision: 0.25-cm3.
2. Condenser--capable of cooling the oil and water vapors below
their liquification temperature.
3. Heating jacket--nominal 350 watts.
4. Temperature control--capable of limiting temperature of
retort to at least 930 deg.F (500 deg.C) and enough to boil off
all NAFs.
b. Liquid receiver (10-cm3, 20-cm3)--the
10-cm3 and 20-cm3 receivers are specially
designed cylindrical glassware with rounded bottom to facilitate
cleaning and funnel-shaped top to catch falling drops. For
compliance monitoring under the NPDES program, the analyst shall use
the 10-cm3 liquid receiver with 0.1 ml graduations to
achieve greater accuracy.
1. Receiver specifications:
Total volume: 10-cm3, 20-cm3.
Precision (0 to 100%): 0.05 cm3,
0.05 cm3.
Outside diameter: 10-mm, 13-mm.
Wall thickness: 1.50.1mm, 1.20.1mm.
Frequency of graduation marks (0 to 100%): 0.10-cm3,
0.10-cm3.
Calibration: To contain ``TC'' @ 20 deg.C.
Scale: cm3, cm3
2. Material--Pyrex or equivalent glass.
c. Toploading balance--capable of weighing 2000 g and precision
of at least 0.1 g. Unless motion is a problem, the analyst shall use
an electronic balance. Where motion is a problem, the analyst may
use a triple beam balance.
d. Fine steel wool (No. 000)--for packing retort body.
e. Thread sealant lubricant: high temperature lubricant, e.g.
Never-Seez or equivalent.
f. Pipe cleaners--to clean condenser and retort stem.
g. Brush--to clean receivers.
h. Retort spatula--to clean retort cup.
i. Corkscrew--to remove spent steel wool.
3. Procedure
a. Clean and dry the retort assembly and condenser.
b. Pack the retort body with steel wool.
c. Apply lubricant/sealant to threads of retort cup and retort
stem.
d. Weigh and record the total mass of the retort cup, lid, and
retort body with steel wool. This is mass (A), grams.
e. Collect a representative cuttings sample (see Note in Section
1 of this appendix).
f. Partially fill the retort cup with cuttings and place the lid
on the cup.
g. Screw the retort cup (with lid) onto the retort body, weigh
and record the total mass. This is mass (B), grams.
h. Attach the condenser. Place the retort assembly into the
heating jacket.
i. Weigh and record the mass of the clean and dry liquid
receiver. This is mass (C), grams. Place the receiver below
condenser outlet.
j. Turn on the retort. Allow it to run a minimum of 1 hour.
Note: If solids boil over into receiver, the test shall be
rerun. Pack the retort body with a greater amount of steel wool and
repeat the test.
k. Remove the liquid receiver. Allow it to cool. Record the
volume of water recovered. This is (V), cm\3\.
Note: If an emulsion interface is present between the oil and
water phases, heating the interface may break the emulsion. As a
suggestion, remove the retort assembly from the heating jacket by
grasping the condenser. Carefully heat the receiver along the
emulsion band by gently touching the receiver for short intervals
with the hot retort assembly. Avoid boiling the liquids. After the
emulsion interface is broken, allow the liquid receiver to cool.
Read the water volume at the lowest point of the meniscus.
l. Weigh and record the mass of the receiver and its liquid
contents (oil plus water). This is mass (D), grams.
m. Turn off the retort. Remove the retort assembly and condenser
from the heating jacket and allow them to cool. Remove the
condenser.
n. Weigh and record the mass of the cooled retort assembly
without the condenser. This is mass (E), grams.
o. Clean the retort assembly and condenser.
4. Calculations
a. Calculate the mass of oil (NAF base fluid) from the cuttings
as follows:
1. Mass of the wet cuttings sample (Mw) equals the
mass of the retort assembly with the wet cuttings sample (B) minus
the mass of the empty retort assembly (A).
Mw = B-A [1]
2. Mass of the dry retorted cuttings (MD) equals the
mass of the cooled retort assembly (E) minus the mass of the empty
retort assembly (A).
MD = E-A [2]
3. Mass of the NAF base fluid (MBF) equals the mass
of the liquid receiver with its contents (D) minus the sum of the
mass of the dry receiver (C) and the mass of the water (V).
MBF = D-(C + V) [3]
Note: Assuming the density of water is 1 g/cm\3\, the volume of
water is equivalent to the mass of the water.
b. Mass balance requirement:
The sum of MD, MBF, and V shall be within
5% of the mass of the wet sample.
(MD + MBF + V)/Mw = 0.95 to 1.05
[4]
The procedure shall be repeated if this requirement is not met.
c. Reporting oil from cuttings:
1. Assume that all oil recovered is NAF base fluid.
2. The mass percent NAF base fluid retained on the cuttings
(%BFi) for the sampled discharge ``i'' is equal to 100
times the mass of the NAF base fluid (MBF) divided by the
mass of the wet cuttings sample (Mw).
%BFi = (MBF/Mw) x 100 [5]
Operators discharging small volume NAF-cuttings discharges which
do not occur during a NAF-cuttings discharge sampling interval
(i.e., displaced interfaces, accumulated solids in sand traps, pit
clean-out solids, or centrifuge discharges while cutting mud weight)
shall either: (a) Measure the mass percent NAF base fluid retained
on the cuttings (%BFSVD) for each small volume NAF-
cuttings discharges; or (b) use a default value of 25% NAF base
fluid retained on the cuttings.
3. The mass percent NAF base fluid retained on the cuttings is
determined for all cuttings wastestreams and includes fines
discharges and any accumulated solids discharged [see Section 4.c.6
of this appendix for procedures on measuring or estimating the mass
percent NAF base fluid retained on the cuttings (%BF) for dual
gradient drilling seafloor discharges performed to ensure proper
operation of subsea pumps].
4. A mass NAF-cuttings discharge fraction (X, unitless) is
calculated for all NAF-cuttings, fines, or accumulated solids
discharges every time a set of retorts is performed (see Section
4.c.6 of this appendix for procedures on measuring or estimating the
mass NAF-cuttings discharge fraction (X) for dual gradient drilling
seafloor discharges performed to ensure proper operation of subsea
pumps). The mass NAF-cuttings discharge fraction (X) combines the
mass of NAF-cuttings, fines, or accumulated solids discharged from a
particular discharge over a set period of time with the total mass
of NAF-cuttings, fines, or accumulated solids discharged into the
ocean during the same period of time (see Addendum A and B of this
appendix). The mass NAF-cuttings discharge fraction (X) for each
discharge is calculated by direct measurement as:
Xi = (Fi)/(G) [6]
where:
Xi = Mass NAF-cuttings discharge fraction for NAF-
cuttings, fines, or accumulated solids discharge ``i'', (unitless)
Fi = Mass of NAF-cuttings discharged from NAF-cuttings,
fines, or accumulated solids discharge ``i'' over a specified period
of time (see Addendum A and B of this appendix), (kg)
G = Mass of all NAF-cuttings discharges into the ocean during the
same period of time as used to calculate Fi, (kg)
If an operator has more than one point of NAF-cuttings
discharge, the mass faction (Xi) must be determined by:
(a) Direct measurement (see Equation 6 of this
[[Page 6911]]
Appendix); (b) using the following default values of 0.85 and 0.15
for the cuttings dryer (e.g., horizontal centrifuge, vertical
centrifuge, squeeze press, High-G linear shakers) and fines removal
unit (e.g., decanting centrifuges, mud cleaners), respectively, when
the operator is only discharging from the cuttings dryer and the
fines removal unit; or (c) using direct measurement of
``Fi'' (see Equation 6 of this Appendix) for fines and
accumulated solids, using Equation 6A of this Appendix to calculate
``GEST'' for use as ``G'' in Equation 6 of this Appendix,
and calculating the mass (kg) of NAF-cuttings discharged from the
cuttings dryer (Fi) as the difference between the mass of
``GEST'' calculated in Equation 6A of this appendix (kg)
and the sum of all fines and accumulated solids mass directly
measured (kg) (see Equation 6 of this Appendix).
GEST = Estimated mass of all NAF-cuttings discharges into
the ocean during the same period of time as used to calculate
Fi (see Equation 6 of this Appendix), (kg) [6A]
where:
GEST = Hole Volume (bbl) x (396.9 kg/bbl) x (1 + Z/
100)
Z = The base fluid retained on cuttings limitation or standard (%)
which apply to the NAF being discharge (see Secs. 435.13. and
435.15).
Hole Volume (bbl) = [Cross-Section Area of NAF interval
(in2)] x Average Rate of Penetration (feet/hr) x
period of time (min) used to calculate Fi (see Equation 6
of this Appendix) x (1 hr/60 min) x (1 bbl/5.61 ft3)
x (1 ft/12 in)2
Cross-Section Area of NAF interval (in2) = (3.14 x [Bit
Diameter (in)]2)/4
Bit Diameter (in) = Diameter of drilling bit for the NAF interval
producing drilling cuttings during the same period of time as used
to calculate Fi (see Equation 6 of this Appendix)
Average Rate of Penetration (feet/hr) = Arithmetic average of rate
of penetration into the formation during the same period of time as
used to calculate Fi (see Equation 6 of this Appendix)
Note: Operators with one NAF-cuttings discharge may set the mass
NAF-cuttings discharge fraction (Xi) equal to 1.0.
5. Each NAF-cuttings, fines, or accumulated solids discharge has
an associated mass percent NAF base fluid retained on cuttings value
(%BF) and mass NAF-cuttings discharge fraction (X) each time a set
of retorts is performed. A single total mass percent NAF base fluid
retained on cuttings value (%BFT) is calculated every
time a set of retorts is performed. The single total mass percent
NAF base fluid retained on cuttings value (%BFT) is
calculated as:
%BFT,j = (Xi) x (%BFi)
[7]
where:
%BFT,j = Total mass percent NAF base fluid retained on
cuttings value for retort set ``j'' (unitless as percentage, %)
Xi = Mass NAF-cuttings discharge fraction for NAF-
cuttings, fines, or accumulated solids discharge ``i'', (unitless)
%BFi = Mass percent NAF base fluid retained on the
cuttings for NAF-cuttings, fines, or accumulated solids discharge
``i'' , (unitless as percentage, %)
Note: Xi = 1.
Operators with one NAF-cuttings discharge may set
%BFT,j equal to %BFi.
6. Operators performing dual gradient drilling operations may
require seafloor discharges of large cuttings (>\1/4\") to ensure
the proper operation of subsea pumps (e.g., electrical submersible
pumps). Operators performing dual gradient drilling operations which
lead to seafloor discharges of large cuttings for the proper
operation of subsea pumps shall either: (a) Measure the mass percent
NAF base fluid retained on cuttings value (%BF) and mass NAF-
cuttings discharge fraction (X) for seafloor discharges each time a
set of retorts is performed; (b) use the following set of default
values, (%BF=14%; X=0.15); or (c) use a combination of (a) and (b)
(e.g., use a default value for %BF and measure X).
Additionally, operators performing dual gradient drilling
operations which lead to seafloor discharges of large cuttings for
the proper operation of subsea pumps shall also perform the
following tasks:
(a) Use side scan sonar or shallow seismic to determine the
presence of high density chemosynthetic communities. Chemosynthetic
communities are assemblages of tube worms, clams, mussels, and
bacterial mats that occur at natural hydrocarbon seeps or vents,
generally in water depths of 500 meters or deeper. Seafloor
discharges of large cuttings for the proper operation of subsea
pumps shall not be permitted within 1000 feet of a high density
chemosynthetic community.
(b) Seafloor discharges of large cuttings for the proper
operation of subsea pumps shall be visually monitored and documented
by a Remotely Operated Vehicle (ROV) within the tether limit
(approximately 300 feet). The visual monitoring shall be conducted
prior to each time the discharge point is relocated (cuttings
discharge hose) and conducted along the same direction as the
discharge hose position. Near-seabed currents shall be obtained at
the time of the visual monitoring.
(c) Seafloor discharges of large cuttings for the proper
operation of subsea pumps shall be directed within a 150 foot radius
of the wellbore.
7. The weighted mass ratio averaged over all NAF well sections
(%BFwell) is the compliance value that is compared with
the ``maximum weighted mass ratio averaged over all NAF well
sections'' BAT discharge limitations (see the table in Sec. 435.13
and footnote 5 of the table in Sec. 435.43) or the ``maximum
weighted mass ratio averaged over all NAF well sections'' NSPS
discharge limitations (see the table in Sec. 435.15 and footnote 5
of the table in Sec. 435.45). The weighted mass ratio averaged over
all NAF well sections (%BFwell) is calculated as the
arithmetic average of all total mass percent NAF base fluid retained
on cuttings values (%BFT) and is given by the following
expression:
%BFwell = [j=1 to j=n (%BFT,j)]/n
[8]
where:
%BFwell = Weighted mass ratio averaged over all NAF well
sections (unitless as percentage, %)
%BFT,j = Total mass percent NAF base fluid retained on
cuttings value for retort set ``j'' (unitless as percentage, %)
n = Total number of retort sets performed over all NAF well sections
(unitless)
Small volume NAF-cuttings discharges which do not occur during a
NAF-cuttings discharge sampling interval (i.e., displaced
interfaces, accumulated solids in sand traps, pit clean-out solids,
or centrifuge discharges while cutting mud weight) shall be mass
averaged with the arithmetic average of all total mass percent NAF
base fluid retained on cuttings values (see Equation 8 of this
Appendix). An additional sampling interval shall be added to the
calculation of the weighted mass ratio averaged over all NAF well
sections (%BFwell). The mass fraction of the small volume
NAF-cuttings discharges (XSVD) will be determined by
dividing the mass of the small volume NAF-cuttings discharges
(FSVD) by the total mass of NAF-cuttings discharges for
the well drilling operation (GWELL + FSVD).
XSVD = FSVD / (GWELL +
FSVD) [9]
where:
XSVD = mass fraction of the small volume NAF-cuttings
discharges (unitless)
FSVD = mass of the small volume NAF-cuttings discharges
(kg)
GWELL = mass of total NAF-cuttings from the well (kg)
The mass of small volume NAF-cuttings discharges
(FSVD) shall be determined by multiplying the density of
the small volume NAF-cuttings discharges (svd)
times the volume of the small volume NAF-cuttings discharges
(VSVD).
FSVD = svd x VSVD [10]
where:
FSVD = mass of small volume NAF-cuttings discharges (kg)
svd = density of the small volume NAF-cuttings
discharges (kg/bbl)
VSVD = volume of the small volume NAF-cuttings discharges
(bbl)
The density of the small volume NAF-cuttings discharges shall be
measured. The volume of small volume discharges (VSVD)
shall be either: (a) Be measured or (b) use default values of 10 bbl
of SBF for each interface loss and 75 bbl of SBM for pit cleanout
per well.
The total mass of NAF-cuttings discharges for the well
(GWELL) shall be either: (a) Measured; or (b) calculated
by multiplying 1.0 plus the arithmetic average of all total mass
percent NAF base fluid retained on cuttings values [see Equation 8
of this Appendix] times the total hole volume (VWELL) for
all NAF well sections times a default value for the density the
formation of 2.5 g/cm3 (396.9 kg/bbl).
[[Page 6912]]
[GRAPHIC] [TIFF OMITTED] TR22JA01.161
where:
GWELL = total mass of NAF-cuttings discharges for the
well (kg)
[j = 1 to j = n 2(%BFTj)]/n = see Equation 8 of
this Appendix (unitless as a percentage)
VWELL = total hole volume (VWELL) for all NAF
well sections (bbl)
The total hole volume of NAF well sections (VWELL)
will be calculated as:
[GRAPHIC] [TIFF OMITTED] TR22JA01.170
For wells where small volume discharges associated with cuttings
are made, %BFWELL becomes:
[GRAPHIC] [TIFF OMITTED] TR22JA01.171
Note: See Addendum A and B to determine the sampling frequency
to determine the total number of retort sets required for all NAF
well sections.
8. The total number of retort sets (n) is increased by 1 for
each sampling interval (see Section 2.4, Addendum A of this
appendix) when all NAF cuttings, fines, or accumulated solids for
that sampling interval are retained for no discharge. A zero
discharge interval shall be at least 500 feet up to a maximum of
three per day. This action has the effect of setting the total mass
percent NAF base fluid retained on cuttings value (%BFT)
at zero for that NAF sampling interval when all NAF cuttings, fines,
or accumulated solids are retained for no discharge.
9. Operators that elect to use the Best Management Practices
(BMPs) for NAF-cuttings shall use the procedures outlined in
Addendum B.
Addendum A to Appendix 7 to Subpart A of Part 435--Sampling of Cuttings
Discharge Streams for use with API Recommended Practice 13B-2
1.0 Sampling Locations
1.1 Each NAF-cuttings waste stream that discharges into the
ocean shall be sampled and analyzed as detailed in Appendix 7. NAF-
cuttings discharges to the ocean may include discharges from primary
shakers, secondary shakers, cuttings dryer, fines removal unit,
accumulated solids, and any other cuttings separation device whose
NAF-cuttings waste is discharged to the ocean. NAF-cuttings
wastestreams not directly discharged to the ocean (e.g., NAF-
cuttings generated from shake shakers and sent to a cuttings dryer
for additional processing) do not require sampling and analysis.
1.2 The collected samples shall be representative of each NAF-
cuttings discharge. Operators shall conduct sampling to avoid the
serious consequences of error (i.e., bias or inaccuracy). Operators
shall collect NAF-cuttings samples near the point of origin and
before the solids and liquid fractions of the stream have a chance
to separate from one another. For example, operators shall collect
shale shaker NAF-cuttings samples at the point where NAF-cuttings
are coming off the shale shaker and not from a holding container
downstream where separation of larger particles from the liquid can
take place.
1.3 Operators shall provide a simple schematic diagram of the
solids control system and sample locations to the NPDES permit
controlling authority.
2.0 Type of Sample and Sampling Frequency
2.1 Each NAF-cuttings, fines, or accumulated solids discharge
has an associated mass percent NAF base fluid retained on cuttings
value (%BF) and mass NAF-cuttings discharge fraction (X) for each
sampling interval (see Section 2.4 of this addendum). Operators
shall collect a single discrete NAF-cuttings sample for each NAF-
cuttings waste stream discharged to the ocean during every sampling
interval.
2.2 Operators shall use measured depth in feet from the Kelly
bushing when samples are collected.
2.3 The NAF-cuttings samples collected for the mass fraction
analysis (see Equation 6, Appendix 7 of Subpart A of this part)
shall also be used for the retort analysis (see Equations 1-5,
Appendix 7 of Subpart A of this part).
2.4 Operators shall collect and analyze at least one set of
NAF-cuttings samples per day while discharging. Operators engaged in
fast drilling (i.e., greater than 500 linear NAF feet advancement of
drill bit per day) shall collect and analyze one set of NAF-cuttings
samples per 500 linear NAF feet of footage drilled. Operators are
not required to collect and analyze more than three sets of NAF-
cuttings samples per day (i.e., three sampling intervals). Operators
performing zero discharge of all NAF-cuttings (i.e., all NAF
cuttings, fines, or accumulated solids retained for no discharge)
shall use the following periods to count sampling intervals: (1) One
sampling interval per day when drilling is less than 500 linear NAF
feet advancement of drill bit per day; and (2) one sampling interval
per 500 linear NAF feet of footage drilled with a maximum of three
sampling intervals per day.
2.5 The operator shall measure the individual masses
(Fi, kg) and sum total mass (G, kg) (see Equation 6,
Appendix 7 of subpart A of this part) over a representative period
of time (e.g., 10 minutes) during steady-state conditions for each
sampling interval (see Section 2.4 of this addendum). The operator
shall ensure that all NAF-cuttings are capture for mass analysis
during the same sampling time period (e.g., 10 minutes) at
approximately the same time (i.e., all individual mass samples
collected within one hour of each other).
2.6 Operators using Best Management Practices (BMPs) to control
NAF-cuttings discharges shall follow the procedures in Addendum B to
Appendix 7 of subpart A of 40 CFR 435.
3.0 Sample Size and Handling
3.1 The volume of each sample depends on the volumetric flow
rate (cm\3\/s) of the NAF-cuttings stream and the sampling time
period (e.g., 10 minutes). Consequently, different solids control
equipment units producing different NAF-cuttings waste streams at
different volumetric flow rates will produce different size samples
for the same period of time. Operators shall use appropriately sized
sample containers for each NAF-cuttings waste stream to ensure no
NAF-cuttings are spilled during sample collection. Operators shall
use the same time period (e.g., 10 minutes) to collect NAF-cuttings
samples from each NAF-cuttings waste stream. Each NAF-cuttings
sample size shall be at least one gallon. Operators shall clearly
mark each container to identify each NAF-cuttings sample.
3.2 Operators shall not decant, heat, wash, or towel the NAF-
cuttings to remove NAF base fluid before mass and retort analysis.
3.3 Operators shall first calculate the mass of each NAF-
cuttings sample and perform the mass ratio analysis (see Equation 6,
Appendix 7 of subpart A of this part). Operators with only one NAF-
cuttings discharge may skip this step (see Section 4.c.4, Appendix 7
of subpart A of this part).
3.4 Operators shall homogenize (e.g., stirring, shaking) each
NAF-cuttings sample prior to placing a sub-sample into the retort
cup. The bottom of the NAF-cuttings sample container shall be
examined to be sure that solids are not sticking to it.
3.5 Operators shall then calculate the NAF base fluid retained
on cuttings using the retort procedure (see Equations 1-5, Appendix
7 of subpart A of this part). Operators shall start the retort
analyses no more than two hours after collecting the first
individual mass sample for the sampling interval .
3.6 Operators shall not discharge any sample before
successfully completing the mass and retort analyses [i.e., mass
balance
[[Page 6913]]
requirements (see Section 4.b, Appendix 7 of subpart A of this part)
are satisfied]. Operators shall immediately re-run the retort
analyses if the mass balance requirements (see Equation 4, Appendix
7 of subpart A of this part) are not within a tolerance of 5% (see
Section 4.b, Equation 4, Appendix 7 of subpart A of this part).
4.0 Calculations
4.1 Operators shall calculate a set of mass percent NAF base
fluid retained on cuttings values (%BF) and mass NAF-cuttings
discharge fractions (X) for each NAF-cuttings waste stream (see
Section 1.1 of this addendum) for each sampling interval (see
Section 2.4 of this addendum) using the procedures outlined in
Appendix 7 of subpart A of this part.
4.2 Operators shall tabulate the following data for each
individual NAF-cuttings sample: (1) Date and time of NAF-cuttings
sample collection; (2) time period of NAF-cuttings sample collection
(see Section 3.1 of this addendum); (3) mass and volume of each NAF-
cuttings sample; (4) measured depth (feet) at NAF-cuttings sample
collection (see Section 2.2 of this addendum); (5) respective linear
feet of hole drilled represented by the NAF-cuttings sample (feet);
and (6) the drill bit diameter (inches) used to generate the NAF-
cuttings sample cuttings.
4.3 Operators shall calculate a single total mass percent NAF
base fluid retained on cuttings value (%BFT) for each
sampling interval (see Section 2.4 of this addendum) using the
procedures outlined in Appendix 7 of Subpart A of this part.
4.4 Operators shall tabulate the following data for each total
mass percent NAF base fluid retained on cuttings value
(%BFT) for each NAF-cuttings sampling interval: (1) Date
and starting and stopping times of NAF-cuttings sample collection
and retort analyses; (2) measured depth of well (feet) at start of
NAF-cuttings sample collection (see Section 2.2 of this addendum);
(3) respective linear feet of hole drilled represented by the NAF-
cuttings sample (feet); (4) the drill bit diameter (inches) used to
generate the NAF-cuttings sample cuttings; and (5) annotation when
zero discharge of NAF-cuttings is performed.
4.5 Operators shall calculate the weighted mass ratio averaged
over all NAF well sections (%BFwell) using the procedures
outlined in Appendix 7 of Subpart A of this part.
4.6 Operators shall tabulate the following data for each
weighted mass ratio averaged over all NAF well sections
(%BFwell) for each NAF well: (1) Starting and stopping
dates of NAF well sections; (2) measured depth (feet) of all NAF
well sections; (3) total number of sampling intervals (see Section
2.4 and Section 2.6 of this addendum); (4) number of sampling
intervals tabulated during any zero discharge operations; (5) total
volume of zero discharged NAF-cuttings over entire NAF well
sections; and (6) identification of whether BMPs were employed (see
Addendum B of Appendix 7 of subpart A of this part).
Addendum B to Appendix 7 to Subpart A of Part 435-- Best Management
Practices (BMPs) for use with API Recommended Practice 13B-2
1.0 Overview of BMPs
1.1 Best Management Practices (BMPs) are inherently pollution
prevention practices. BMPs may include the universe of pollution
prevention encompassing production modifications, operational
changes, material substitution, materials and water conservation,
and other such measures. BMPs include methods to prevent toxic and
hazardous pollutants from reaching receiving waters. Because BMPs
are most effective when organized into a comprehensive facility BMP
Plan, operators shall develop a BMP in accordance with the
requirements in this addendum.
1.2 The BMP requirements contained in this appendix were
compiled from several Regional permits, an EPA guidance document
(i.e., Guidance Document for Developing Best Management Practices
(BMP)'' (EPA 833-B-93-004, U.S. EPA, 1993)), and draft industry
BMPs. These common elements represent the appropriate mix of broad
directions needed to complete a BMP Plan along with specific tasks
common to all drilling operations.
1.3 Operators are not required to use BMPs if all NAF-cuttings
discharges are monitored in accordance with Appendix 7 of Subpart A
of this part.
2.0 BMP Plan Purpose and Objectives
2.1 Operators shall design the BMP Plan to prevent or minimize
the generation and the potential for the discharge of NAF from the
facility to the waters of the United States through normal
operations and ancillary activities. The operator shall establish
specific objectives for the control of NAF by conducting the
following evaluations.
2.2 The operator shall identify and document each NAF well that
uses BMPs before starting drilling operations and the anticipated
total feet to be drilled with NAF for that particular well.
2.3 Each facility component or system controlled through use of
BMPs shall be examined for its NAF-waste minimization opportunities
and its potential for causing a discharge of NAF to waters of the
United States due to equipment failure, improper operation, natural
phenomena (e.g., rain, snowfall).
2.4 For each NAF wastestream controlled through BMPs where
experience indicates a reasonable potential for equipment failure
(e.g., a tank overflow or leakage), natural condition (e.g.,
precipitation), or other circumstances to result in NAF reaching
surface waters, the BMP Plan shall include a prediction of the total
quantity of NAF which could be discharged from the facility as a
result of each condition or circumstance.
3.0 BMP Plan Requirements
3.1 The BMP Plan may reflect requirements within the pollution
prevention requirements required by the Minerals Management Service
(see 30 CFR 250.300) or other Federal or State requirements and
incorporate any part of such plans into the BMP Plan by reference.
3.2 The operator shall certify that its BMP Plan is complete,
on-site, and available upon request to EPA or the NPDES Permit
controlling authority. This certification shall identify the NPDES
permit number and be signed by an authorized representative of the
operator. This certification shall be kept with the BMP Plan. For
new or modified NPDES permits, the certification shall be made no
later than the effective date of the new or modified permit. For
existing NPDES permits, the certification shall be made within one
year of permit issuance.
3.3 The BMP Plan shall:
3.3.1 Be documented in narrative form, and shall include any
necessary plot plans, drawings or maps, and shall be developed in
accordance with good engineering practices. At a minimum, the BMP
Plan shall contain the planning, development and implementation, and
evaluation/reevaluation components. Examples of these components are
contained in ``Guidance Document for Developing Best Management
Practices (BMP)'' (EPA 833-B-93-004, U.S. EPA, 1993).
3.3.2 Include the following provisions concerning BMP Plan
review.
3.3.2.1 Be reviewed by permittee's drilling engineer and
offshore installation manager (OIM) to ensure compliance with the
BMP Plan purpose and objectives set forth in Section 2.0.
3.3.2.2 Include a statement that the review has been completed
and that the BMP Plan fulfills the BMP Plan purpose and objectives
set forth in Section 2.0. This statement shall have dated signatures
from the permittee's drilling engineer and offshore installation
manager and any other individuals responsible for development and
implementation of the BMP Plan.
3.4 Address each component or system capable of generating or
causing a release of significant amounts of NAF and identify
specific preventative or remedial measures to be implemented.
4.0 BMP Plan Documentation
4.1 The operator shall maintain a copy of the BMP Plan and
related documentation (e.g., training certifications, summary of the
monitoring results, records of NAF-equipment spills, repairs, and
maintenance) at the facility and shall make the BMP Plan and related
documentation available to EPA or the NPDES Permit controlling
authority upon request.
5.0 BMP Plan Modification
5.1 For those NAF wastestreams controlled through BMPs, the
operator shall amend the BMP Plan whenever there is a change in the
facility or in the operation of the facility which materially
increases the generation of those NAF-wastes or their release or
potential release to the receiving waters.
5.2 At a minimum the BMP Plan shall be reviewed once every five
years and amended within three months if warranted. Any such changes
to the BMP Plan shall be consistent with the objectives and specific
requirements listed in this addendum. All changes in the BMP Plan
shall be reviewed by the permittee's drilling engineer and offshore
installation manager.
[[Page 6914]]
5.3 At any time, if the BMP Plan proves to be ineffective in
achieving the general objective of preventing and minimizing the
generation of NAF-wastes and their release and potential release to
the receiving waters and/or the specific requirements in this
addendum, the permit and/or the BMP Plan shall be subject to
modification to incorporate revised BMP requirements.
6.0 Specific Pollution Prevention Requirements for NAF Discharges
Associated with Cuttings
6.1 The following specific pollution prevention activities are
required in a BMP Plan when operators elect to control NAF
discharges associated with cuttings by a set of BMPs.
6.2 Establishing programs for identifying, documenting, and
repairing malfunctioning NAF equipment, tracking NAF equipment
repairs, and training personnel to report and evaluate
malfunctioning NAF equipment.
6.3 Establishing operating and maintenance procedures for each
component in the solids control system in a manner consistent with
the manufacturer's design criteria.
6.4 Using the most applicable spacers, flushes, pills, and
displacement techniques in order to minimize contamination of
drilling fluids when changing from water-based drilling fluids to
NAF and vice versa.
6.5 A daily retort analysis shall be performed (in accordance
with Appendix 7 to subpart A of Part 435) during the first 0.33 X
feet drilled with NAF where X is the anticipated total feet to be
drilled with NAF for that particular well. The retort analyses shall
be documented in the well retort log. The operators shall use the
calculation procedures detailed in Appendix 7 to subpart A of part
435 (see Equations 1 through 8) to determine the arithmetic average
(%BFwell) of the retort analyses taken during the first
0.33 X feet drilled with NAF.
6.5.1 When the arithmetic average (%BFwell) of the
retort analyses taken during the first 0.33 X feet drilled with NAF
is less than or equal to the base fluid retained on cuttings
limitation or standard (see Secs. 435.13 and 435.15), retort
monitoring of cuttings may cease for that particular well. The same
BMPs and drilling fluid used during the first 0.33 X feet shall be
used for all remaining NAF sections for that particular well.
6.5.2 When the arithmetic average (%BFwell) of the
retort analyses taken during the first 0.33 X feet drilled with NAF
is greater the base fluid retained on cuttings limitation or
standard (see Secs. 435.13 and 435.15), retort monitoring shall
continue for the following (second) 0.33 X feet drilled with NAF
where X is the anticipated total feet to be drilled with NAF for
that particular well. The retort analyses for the first and second
0.33 X feet shall be documented in the well retort log.
6.5.2.1 When the arithmetic average (%BFwell) of the
retort analyses taken during the first 0.66 X feet (i.e., retort
analyses taken from first and second 0.33 X feet) drilled with NAF
is less than or equal to the base fluid retained on cuttings
limitation or standard (see Secs. 435.13 and 435.15), retort
monitoring of cuttings may cease for that particular well. The same
BMPs and drilling fluid used during the first 0.66 X feet shall be
used for all remaining NAF sections for that particular well.
6.5.2.2 When the arithmetic average (%BFwell) of the
retort analyses taken during the first 0.66 X feet (i.e., retort
analyses taken from first and second 0.33 X feet) drilled with NAF
is greater than the base fluid retained on cuttings limitation or
standard (see Secs. 435.13 and 435.15), retort monitoring shall
continue for all remaining NAF sections for that particular well.
The retort analyses for all NAF sections shall be documented in the
well retort log.
6.5.3 When the arithmetic average (%BFwell) of the
retort analyses taken over all NAF sections for the entire well is
greater that the base fluid retained on cuttings limitation or
standard (see Secs. 435.13 and 435.15), the operator is in violation
of the base fluid retained on cuttings limitation or standard and
shall submit notification of these monitoring values in accordance
with NPDES permit requirements. Additionally, the operator shall, as
part of the BMP Plan, initiate a reevaluation and modification to
the BMP Plan in conjunction with equipment vendors and/or industry
specialists.
6.5.4 The operator shall include retort monitoring data and
dates of retort-monitored and non-retort-monitored NAF-cuttings
discharges managed by BMPs in their NPDES permit reports.
6.6 Establishing mud pit and equipment cleaning methods in such
a way as to minimize the potential for building-up drill cuttings
(including accumulated solids) in the active mud system and solids
control equipment system. These cleaning methods shall include but
are not limited to the following procedures.
6.6.1 Ensuring proper operation and efficiency of mud pit
agitation equipment.
6.6.2 Using mud gun lines during mixing operations to provide
agitation in dead spaces.
6.6.3 Pumping drilling fluids off of drill cuttings (including
accumulated solids) for use, recycle, or disposal before using wash
water to dislodge solids.
Appendix 8 to Subpart A of Part 435--Reference C16-
C18 Internal Olefin Drilling Fluid Formulation
The reference C16-C18 internal olefin
drilling fluid used to determine the drilling fluid sediment
toxicity ratio and compliance with the BAT sediment toxicity
discharge limitation (see Sec. 435.13) and NSPS (see Sec. 435.15)
shall be formulated to meet the specifications in Table 1 of this
appendix.
Drilling fluid sediment toxicity ratio = 4-day LC50
of C16-C18 internal olefin drilling fluid/4-
day LC50 of drilling fluid removed from cuttings at the
solids control equipment as determined by ASTM E1367-92
[incorporated by reference and specified at Sec. 435.11(ee)] and
supplemented with the sediment preparation procedure (Appendix 3 of
subpart A of this part).
Table 1.--Properties for Reference C16-C18 IOs SBF Used in Discharge Sediment Toxicity Testing
----------------------------------------------------------------------------------------------------------------
Reference C16-C18 IOs
Mud weight of SBF discharged with cuttings (pounds per gallon) Reference C16-C18 IOs SBF synthetic to water
SBF (pounds per gallon) ratio (%)
----------------------------------------------------------------------------------------------------------------
8.5-11........................................................ 9.0 75/25
11-14......................................................... 11.5 80/20
>14........................................................... 14.5 85/15
================================================================================================================
Plastic Viscosity (PV), centipoise (cP)....................... 12-30
Yield Point (YP), pounds/100 sq. ft........................... 10-20
10-second gel, pounds/100 sq. ft.............................. 8-15
10-minute gel, pounds/100 sq. ft.............................. 12-30
Electrical stability, V....................................... >300
----------------------------------------------------------------------------------------------------------------
Subpart D--Coastal Subcategory
8. Section 435.41 is amended by revising paragraphs (b) through
(ff) and by adding paragraphs (gg) through (ii) to read as follows:
Sec. 435.41 Special definitions.
* * * * *
(b) Average of daily values for 30 consecutive days means the
average of the daily values obtained during any 30 consecutive day
period.
(c) Base fluid means the continuous phase or suspending medium of a
drilling fluid formulation.
(d) Base fluid retained on cuttings as applied to BAT effluent
limitations and NSPS refers to the American Petroleum Institute
Recommended Practice 13B-2
[[Page 6915]]
supplemented with the specifications, sampling methods, and averaging
method for retention values provided in Appendix 7 of subpart A of this
part.
(e) Biodegradation rate as applied to BAT effluent limitations and
NSPS for drilling fluids and drill cuttings refers to the ISO
11734:1995 method: ``Water quality--Evaluation of the `ultimate'
anaerobic biodegradability of organic compounds in digested sludge--
Method by measurement of the biogas production (1995 edition)''
(Available from the American National Standards Institute, 11 West 42nd
Street, 13th Floor, New York, NY 10036) supplemented with modifications
in Appendix 4 of subpart A of this part.
(f) Cook Inlet refers to coastal locations north of the line
between Cape Douglas on the West and Port Chatham on the east.
(g) Daily values as applied to produced water effluent limitations
and NSPS means the daily measurements used to assess compliance with
the maximum for any one day.
(h) Deck drainage means 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.
(i) Development facility means any fixed or mobile structure
subject to this Subpart that is engaged in the drilling of productive
wells.
(j) Dewatering effluent means wastewater from drilling fluids and
drill cuttings dewatering activities (including but not limited to
reserve pits or other tanks or vessels, and chemical or mechanical
treatment occurring during the drilling solids separation/recycle/
disposal process).
(k) 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, NW.,
Suite 700, Washington, DC. A copy may also be inspected at EPA's Water
Docket, 401 M Street SW., Washington, DC 20460.
(l) Domestic waste means the 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.
(m) Drill cuttings means the particles generated by drilling into
subsurface geologic formations and carried out from the wellbore with
the drilling fluid. Examples of drill cuttings include small pieces of
rock varying in size and texture from fine silt to gravel. Drill
cuttings are generally generated from solids control equipment and
settle out and accumulate in quiescent areas in the solids control
equipment or other equipment processing drilling fluid (i.e.,
accumulated solids).
(1) Wet drill cuttings means the unaltered drill cuttings and
adhering drilling fluid and formation oil carried out from the wellbore
with the drilling fluid.
(2) Dry drill cuttings means the residue remaining in the retort
vessel after completing the retort procedure specified in Appendix 7 of
subpart A of this part.
(n) Drilling fluid means the circulating fluid (mud) used in the
rotary drilling of wells to clean and condition the hole and to
counterbalance formation pressure. Classes of drilling fluids are:
(1) Water-based drilling fluid means the continuous phase and
suspending medium for solids is a water-miscible fluid, regardless of
the presence of oil.
(2) Non-aqueous drilling fluid means the continuous phase and
suspending medium for solids is a water-immiscible fluid, such as
oleaginous materials (e.g., mineral oil, enhanced mineral oil,
paraffinic oil, C16-C18 internal olefins, and
C8-C16 fatty acid/2-ethylhexyl esters).
(i) Oil-based means the continuous phase of the drilling fluid
consists of diesel oil, mineral oil, or some other oil, but contains no
synthetic material or enhanced mineral oil.
(ii) Enhanced mineral oil-based means the continuous phase of the
drilling fluid is enhanced mineral oil.
(iii) Synthetic-based means the continuous phase of the drilling
fluid is a synthetic material or a combination of synthetic materials.
(o) Enhanced mineral oil as applied to enhanced mineral oil-based
drilling fluid means a petroleum distillate which has been highly
purified and is distinguished from diesel oil and conventional mineral
oil in having a lower polycyclic aromatic hydrocarbon (PAH) content.
Typically, conventional mineral oils have a PAH content on the order of
0.35 weight percent expressed as phenanthrene, whereas enhanced mineral
oils typically have a PAH content of 0.001 or lower weight percent PAH
expressed as phenanthrene.
(p) 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.
(q) Formation oil means the oil from a producing formation which is
detected in the drilling fluid, as determined by the GC/MS compliance
assurance method specified in Appendix 5 of subpart A of this part when
the drilling fluid is analyzed before being shipped offshore, and as
determined by the RPE method specified in Appendix 6 of subpart A of
this part when the drilling fluid is analyzed at the offshore point of
discharge. Detection of formation oil by the RPE method may be
confirmed by the GC/MS compliance assurance method, and the results of
the GC/MS compliance assurance method shall supercede those of the RPE
method.
(r) Garbage means all kinds of victual, domestic, and operational
waste, excluding fresh fish and parts thereof, generated during the
normal operation of coastal oil and gas facility and liable to be
disposed of continuously or periodically, except dishwater, graywater,
and those substances that are defined or listed in other Annexes to
MARPOL 73/78. A copy of MARPOL may be inspected at EPA's Water Docket;
401 M Street SW., Washington DC 20460.
(s) M9IM means those offshore facilities continuously manned by
nine (9) or fewer persons or only intermittently manned by any number
of persons.
(t) M10 means those offshore facilities continuously manned by ten
(10) or more persons.
(u) 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 for
determination of cadmium and mercury content.
(v) 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.
(w) 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.
[[Page 6916]]
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.
(x)(1) 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) Water area as used in ``site'' in 40 CFR 122.29 and 122.2 means
the water area and water body floor beneath any exploratory,
development, or production facility where such facility is conducting
its exploratory, development or production activities.
(ii) Significant site preparation work as used in 40 CFR 122.29
means the process of surveying, clearing or preparing an area of the
water body floor for the purpose of constructing or placing a
development or production facility on or over the site.
(2) ``New Source'' does not include facilities covered by an
existing NPDES permit immediately prior to the effective date of these
guidelines pending EPA issuance of a new source NPDES permit.
(y) No discharge of free oil means that waste streams may not be
discharged that contain free oil as evidenced by the monitoring method
specified for that particular stream, e.g., deck drainage or
miscellaneous discharges cannot be discharged when they would cause a
film or sheen upon or discoloration of the surface of the receiving
water; drilling fluids or cuttings may not be discharged when they fail
the static sheen test defined in Appendix 1 of subpart A of this part.
(z) Parameters that are regulated in this subpart and listed with
approved methods of analysis in Table 1B at 40 CFR 136.3 are defined as
follows:
(1) Cadmium means total cadmium.
(2) Chlorine means total residual chlorine.
(3) Mercury means total mercury.
(4) Oil and Grease means total recoverable oil and grease.
(aa) Produced sand means the 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.
(bb) Produced water means 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.
(cc) 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.
(dd) Sanitary waste means the human body waste discharged from
toilets and urinals located within facilities subject to this subpart.
(ee) SPP 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 subpart A of this part.
(ff) Static sheen test means 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 of subpart A of this part.
(gg) Stock barite means the barite that was used to formulate a
drilling fluid.
(hh) Synthetic material as applied to synthetic-based drilling
fluid means material produced by the reaction of specific purified
chemical feedstock, as opposed to the traditional base fluids such as
diesel and mineral oil which are derived from crude oil solely through
physical separation processes. Physical separation processes include
fractionation and distillation and/or minor chemical reactions such as
cracking and hydro processing. Since they are synthesized by the
reaction of purified compounds, synthetic materials suitable for use in
drilling fluids are typically free of polycyclic aromatic hydrocarbons
(PAH's) but are sometimes found to contain levels of PAH up to 0.001
weight percent PAH expressed as phenanthrene. Internal olefins and
vegetable esters are two examples of synthetic materials suitable for
use by the oil and gas extraction industry in formulating drilling
fluids. Internal olefins are synthesized from the isomerization of
purified straight-chain (linear) hydrocarbons such as C16-
C18 linear alpha olefins. C16-C18
linear alpha olefins are unsaturated hydrocarbons with the carbon to
carbon double bond in the terminal position. Internal olefins are
typically formed from heating linear alpha olefins with a catalyst. The
feed material for synthetic linear alpha olefins is typically purified
ethylene. Vegetable esters are synthesized from the acid-catalyzed
esterification of vegetable fatty acids with various alcohols. EPA
listed these two branches of synthetic fluid base materials to provide
examples, and EPA does not mean to exclude other synthetic materials
that are either in current use or may be used in the future. A
synthetic-based drilling fluid may include a combination of synthetic
materials.
(ii) Well completion fluids means 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.
(jj) Well treatment fluids means any fluid used to restore or
improve productivity by chemically or physically altering hydrocarbon-
bearing strata after a well has been drilled.
(kk) Workover fluids means salt solutions, weighted brines,
polymers, or other specialty additives used in a producing well to
allow for maintenance, repair or abandonment procedures.
(ll) 96-hour LC50 means 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.
9. In Sec. 435.42 the table is amended by removing the entries
``Drilling fluids'' and ``Drill cuttings'' and by adding new entries
(after ``Deck drainage'') for ``Water based'' and ``Non-aqueous'' 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).
* * * * *
[[Page 6917]]
BPT Effluent Limitations--Oil and Grease
[In milligrams per liter]
----------------------------------------------------------------------------------------------------------------
Average of values for 30
Pollutant parameter waste source Maximum for any 1 day consecutive days shall Residual chlorine
not exceed minimum for any 1 day
----------------------------------------------------------------------------------------------------------------
* * * * * *
*
Water-based:
Drilling fluids.................. ( \1\).................. ( \1\).................. NA
Drill Cuttings................... ( \1\).................. ( \1\).................. NA
Non-aqueous:
Drilling fluids.................. No discharge............ No discharge............ NA
Drill Cuttings................... ( \1\).................. ( \1\).................. NA
* * * * * *
*
----------------------------------------------------------------------------------------------------------------
\1\ No discharge of free oil.
* * * * *
10. In Sec. 435.43 the table is amended by revising entry (B) under
``Drilling fluids, drill cuttings, and dewatering effluent'' and by
revising footnote 4 and adding footnote 5 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).
* * * * *
BAT Effluent Limitations
------------------------------------------------------------------------
Pollutant BAT effluent
Waste source parameter limitation
------------------------------------------------------------------------
* * * *
* * *
Drilling fluids, Drill
cuttings, and Dewatering
effluent: \1\
* * * *
* * *
(B) Cook Inlet:
Water-based drilling SPP Toxicity..... Minimum 96-hour LC50
fluids, drill cuttings, of the SPP Toxicity
and dewatering effluent. Test 4 shall be 3%
by volume.
Free oil......... No discharge.\2\
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.
Non-aqueous drilling ............... No discharge.
fluids and dewatering
effluent.
Drill cuttings associated ............... No discharge.\5\
with non-aqueous drilling
fluids.
* * * *
* * *
------------------------------------------------------------------------
\1\ BAT limitations for dewatering effluent are applicable
prospectively. BAT limitations in this rule are not applicable to
discharges of dewatering effluent from reserve pits which as of the
effective date of this rule no longer receive drilling fluids and
drill cuttings. Limitations on such discharges shall be determined by
the NPDES permit issuing authority.
\2\ As determined by the static sheen test (see Appendix 1 of Subpart A
of this part).
* * * *
* * *
\4\ As determined by the suspended particulate phase (SPP) toxicity test
(see Appendix 2 of Subpart A of this part).
\5\ When Cook Inlet operators cannot comply with this no discharge
requirement due to technical limitations (see Appendix 1 of Subpart D
of this part), Cook Inlet operators shall meet the same stock
limitations (C16-C18 internal olefin) and discharge limitations for
drill cuttings associated with non-aqueous drilling fluids for
operators in Offshore waters (see Sec. 435.13) in order to discharge
drill cuttings associated with non-aqueous drilling fluids.
11. In Sec. 435.44 the table is amended by revising the entry for
``Cook Inlet'' under the entry for ``Drilling fluids and drill cuttings
and dewatering effluent'' to read as follows:
Sec. 435.44 Effluent limitations guidelines representing the degree of
effluent reduction attainable by the application of the best
conventional pollutant control technology (BCT).
* * * * *
[[Page 6918]]
BCT Effluent Limitations
------------------------------------------------------------------------
Pollutant
Waste source parameter BCT effluent limitation
------------------------------------------------------------------------
* * * *
* * *
Drilling fluids, Drill
cuttings, and Dewatering
effluent: \1\
* * * *
* * *
Cook Inlet:
Water-based drilling Free Oil....... No discharge.\2\
fluids, drill cuttings,
and dewatering effluent.
Non-aqueous drilling ............. No discharge.
fluids and dewatering
effluent.
Drill cuttings associated Free Oil....... No discharge.\2\
with non-aqueous
drilling fluids.
------------------------------------------------------------------------
\1\ BCT limitations for dewatering effluent are applicable
prospectively. BCT limitations in this rule are not applicable to
discharges of dewatering effluent from reserve pits which as of the
effective date of this rule no longer receive drilling fluids and
drill cuttings. Limitations on such discharges shall be determined by
the NPDES permit issuing authority.
\2\ As determined by the static sheen test (see Appendix 1 of Subpart A
of this part).
* * * * *
12. In Sec. 435.45 the table is amended by revising entry (B) under
``Drilling fluids, drill cuttings, and dewatering effluent'' and by
revising footnote 4 and adding footnote 5 to read as follows:
Sec. 435.45 Standards of performance for new sources (NSPS).
* * * * *
New Source Performance Standards (NSPS)
------------------------------------------------------------------------
Pollutant
Waste Source parameter NSPS
------------------------------------------------------------------------
* * * *
* * *
Drilling fluids, Drill
cuttings, and Dewatering
effluent: \1\
* * * *
* * *
(B) Cook Inlet:
Water-based drilling SPP Toxicity..... Minimum 96-hour LC50
fluids, drill cuttings, of the SPP Toxicity
and dewatering effluent. Test \4\ shall be 3%
by volume.
Free oil......... No discharge.\2\
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.
Non-aqueous drilling ............... No discharge.
fluids and dewatering
effluent.
Drill cuttings associated ............... No discharge.\5\
with non-aqueous drilling
fluids.
* * * *
* * *
------------------------------------------------------------------------
\1\ NSPS for dewatering effluent are applicable prospectively. NSPS in
this rule are not applicable to discharges of dewatering effluent from
reserve pits which as of the effective date of this rule no longer
receive drilling fluids and drill cuttings. Limitations on such
discharges shall be determined by the NPDES permit issuing authority.
\2\ As determined by the static sheen test (see Appendix 1 of subpart A
of this part).
* * * *
* * *
\4\ As determined by the suspended particulate phase (SPP) toxicity test
(see Appendix 2 of subpart A of this part).
\5\ When Cook Inlet operators cannot comply with this no discharge
requirement due to technical limitations (see Appendix 1 of subpart D
of this part), Cook Inlet operators shall meet the same stock
limitations (C16-C18 internal olefin) and discharge limitations for
drill cuttings associated with non-aqueous drilling fluids for
operators in Offshore waters (see Sec. 435.15) in order to discharge
drill cuttings associated with non-aqueous drilling fluids.
13. Subpart D is amended by adding Appendix 1 as follows:
Appendix 1 to Subpart D of Part 435--Procedure for Determining When
Coastal Cook Inlet Operators Qualify for an Exemption from the Zero
Discharge Requirement for EMO-Cuttings and SBF-Cuttings in Coastal Cook
Inlet, Alaska
1.0 Scope and Application
This appendix is to be used to determine whether a Cook Inlet,
Alaska, operator in Coastal waters (Coastal Cook Inlet operator)
qualifies for the exemption to the zero discharge requirement
established by 40 CFR 435.43 and 435.45 for drill cuttings
associated with the following non-aqueous drilling fluids: enhanced
mineral oil based drilling fluids (EMO-cuttings) and synthetic-based
drilling fluids (SBF-cuttings). Coastal Cook Inlet operators are
prohibited from discharging oil-based drilling fluids. This appendix
is intended to define those situations under which technical
limitations
[[Page 6919]]
preclude Coastal Cook Inlet operators from complying with the zero
discharge requirement for EMO-cuttings and SBF-cuttings. Coastal
Cook Inlet operators that qualify for this exemption may be
authorized to discharge EMO-cuttings and SBF-cuttings subject to the
limitations applicable to operators in Offshore waters (see subpart
A of this part).
2.0 Method
2.1 Any Coastal Cook Inlet operator must achieve the zero
discharge limit for EMO-cuttings and SBF-cuttings unless it
successfully demonstrates that technical limitations prevent it from
being able to dispose of its EMO-cuttings or SBF-cuttings through
on-site annular disposal, injection into a Class II underground
injection control (UIC) well, or onshore land application.
2.2 To successfully demonstrate that technical limitations
prevent it from being able to dispose of its EMO-cuttings or SBF-
cuttings through on-site annular disposal, a Coastal Cook Inlet
operator must show that it has been unable to establish formation
injection in nearby wells that were initially considered for annular
or dedicated disposal of EMO-cuttings or SBF-cuttings or prove to
the satisfaction of the Alaska Oil and Gas Conservation Commission
(AOGCC) that the EMO-cuttings or SBF-cuttings will be confined to
the formation disposal interval. This demonstration must include:
a. Documentation, including engineering analysis, that shows (1)
an inability to establish formation injection (e.g., formation is
too tight), (2) an inability to confine EMO-cuttings or SBF-cuttings
in disposal formation (e.g., no confining zone or adequate barrier
to confine wastes in formation), or (3) the occurrence of high risk
emergency (e.g., mechanical failure of well, loss of ability to
inject that risks loss of well which would cause significant
economic harm or create a substantial risk to safety); and
b. A risk analysis of alternative disposal options, including
environmental assessment, human health and safety, and economic
impact, that shows discharge as the lowest risk option.
2.3 To successfully demonstrate that technical limitations
prevent it from being able to dispose of its EMO-cuttings or SBF-
cuttings through injection into a Class II UIC well, a Coastal Cook
Inlet operator must show that it has been unable to establish
injection into a Class II UIC well or prove to the satisfaction of
the Alaska Oil and Gas Conservation Commission (AOGCC) that the EMO-
cuttings or SBF-cuttings will be confined to the formation disposal
interval. This demonstration must include:
a. Documentation, including engineering analysis, that shows the
inability to confine EMO-cuttings or SBF-cuttings in a Class II UIC
well (e.g., no confining zone or adequate barrier to confine wastes
in formation);
b. Documentation demonstrating that no Class II UIC well is
accessible (e.g., operator does not own, competitor will not allow
injection); and
c. A risk analysis of alternative disposal option, including
environmental assessment, human health and safety, and economic
impact, that shows discharge as the lowest risk option.
2.4 To successfully demonstrate that technical limitations
prevent it from being able to dispose of its EMO-cuttings or SBF-
cuttings through land application, a Coastal Cook Inlet operator
must show that it has been unable to handle drilling waste or
dispose of EMO-cuttings or SBF-cuttings at an appropriate land
disposal site. This demonstration must include:
a. Documentation of site restrictions that preclude land
application (e.g., no land disposal sites available);
b. Documentation of the platform's lack of capacity for adequate
storage of EMO-cuttings or SBF-cuttings (e.g., limited storage or
room for cuttings transfer); or
c. Documentation of inability to transfer EMO-cuttings or SBF-
cuttings from platform to land for disposal (e.g., extremely low
tides, high wave action).
3.0 Procedure
3.1 Except as described in Section 3.2 of this appendix, a
Coastal Cook Inlet operator believing that it qualifies for the
exemption to the zero discharge requirement for EMO-cuttings or SBF-
cuttings must apply for and obtain an individual NPDES permit prior
to discharging EMO-cuttings or SBF-cuttings to waters of the United
States.
3.2 Discharges occurring as the result a high risk emergency
(e.g., mechanical failure of well, loss of ability to inject that
risks loss of well which would cause significant economic harm or
safety) may be authorized by a general NPDES permit provided that:
a. The Coastal Cook Inlet operator satisfactorily demonstrates
to EPA Region 10 the fulfillment of the other exemption requirements
described in Section 2.0 of this appendix, or
b. The general permit allows for high risk emergency discharges
and provides Reporting Requirements to EPA Region 10 immediately
upon commencing discharge.
[FR Doc. 01-361 Filed 1-19-01; 8:45 am]
BILLING CODE 6560-50-U