[Federal Register Volume 64, Number 22 (Wednesday, February 3, 1999)]
[Proposed Rules]
[Pages 5488-5554]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 99-317]
[[Page 5487]]
_______________________________________________________________________
Part III
Environmental Protection Agency
_______________________________________________________________________
40 CFR Part 435
Effluent Limitations Guidelines and New Source Performance Standards
for Synthetic-Based and Other Non-Aqueous Drilling Fluids in the Oil
and Gas Extraction Point Source Category; Proposed Rule
Federal Register / Vol. 64, No. 22 / Wednesday, February 3, 1999 /
Proposed Rules
[[Page 5488]]
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 435
[FRL-6215-1]
RIN 2040-AD14
Effluent Limitations Guidelines and New Source Performance
Standards for Synthetic-Based and Other Non-Aqueous Drilling Fluids in
the Oil and Gas Extraction Point Source Category
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
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SUMMARY: This proposed rule would amend the technology-based effluent
limitations guidelines for the discharge of certain pollutants into
waters of the United States by existing and new facilities in portions
of the offshore and coastal subcategories of the oil and gas extraction
point source category.
This proposed rule would establish effluent limitations guidelines
and new source performance standards (NSPS) for direct dischargers
based on ``best practicable control technology currently available''
(BPT), ``best conventional pollutant control technology'' (BCT), ``best
available technology economically achievable'' (BAT), and for new
sources ``best available demonstrated control technology'' (BADCT). EPA
is proposing to amend the regulation by providing specific requirements
for the discharge of synthetic-based drilling fluids (SBFs) and other
non-aqueous drilling fluids. The wastestreams that would be limited are
drilling fluids and drill cuttings.
This rule would not amend the current regulations for water-based
drilling fluids. Also, this rule would not amend the zero discharge
requirement for drilling wastes in the coastal subcategory (except Cook
Inlet, Alaska) and in the offshore subcategory within three miles from
shore.
Controlling the discharge of SBFs as proposed today would reduce
the discharge of SBFs by 11.7 million pounds annually. Further,
allowing rather than prohibiting the discharge of SBFs would
substantially reduce non-water quality environmental impacts. Compared
to the zero discharge option, EPA estimates that allowing discharge
will reduce air emissions of the criteria air pollutants by 450 tons
per year, decrease fuel use by 29,000 barrels per year of oil
equivalent, and reduce the generation of oily drill cutting wastes
requiring off-site disposal by 212 million pounds per year.
DATES: Comments on the proposal must be received by May 4, 1999. A
public meeting will be held during the comment period, on Friday, March
5, 1999, from 9:00 a.m. to 12:00 p.m.
ADDRESSES: Send written comments and supporting data on this proposal
to: Mr. Joseph Daly, Office of Water, Engineering and Analysis Division
(4303), U.S. Environmental Protection Agency, 401 M St. SW, Washington,
DC 20460. Please submit any references cited in your comments. EPA
would appreciate an original and two copies of your comments and
enclosures (including references).
The public meeting will be held at the EPA Region 6 Oklahoma Room,
1445 Ross Avenue, Dallas, TX. If you wish to present formal comments at
the public meeting you should have a written copy for submittal. No
meeting materials will be distributed in advance of the public meeting;
all materials will be distributed at the meeting.
The public record is available for review in the EPA Water Docket,
Room EB57, 401 M St. SW, Washington, DC 20460. The public record for
this rulemaking 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. Joseph Daly at (202) 260-7186. For additional economic
information contact Mr. James Covington at (202) 260-5132.
SUPPLEMENTARY INFORMATION:
Regulated Entities: Entities potentially regulated by this action
include:
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Category Examples of regulated entities
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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 (offshore waters
beyond 3 miles from the shoreline,
in any Alaska offshore waters with
no 3-mile restriction, and the
coastal waters of Cook Inlet,
Alaska). Includes certain
facilities covered under Standard
Industrial Classification code 13
and North American Classification
System codes 211111 and 213111.
------------------------------------------------------------------------
The preceding table is not intended to be exhaustive, but rather
provides a guide for readers regarding entities likely to be regulated
by this action. This table lists the types of entities that EPA is now
aware could potentially be regulated by this action. Other types of
entities not listed in the table could also be regulated. To determine
whether your facility is regulated by this action, you should carefully
examine the applicability criteria in 40 CFR Part 435, Subparts A and
D. 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.
Supporting Documentation
The regulations proposed today are supported by several major
documents:
1. ``Development Document for Proposed 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-98-021). Hereafter referred to as the SBF
Development Document, the document presents EPA's technical conclusions
concerning the proposal. This document describes, among other things,
the data collection activities in support of the proposal, the
wastewater treatment technology options, effluent characterization,
estimate of costs to the industry, and estimate of effects on non-water
quality environmental impacts.
2. ``Economic Analysis of Proposed 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-98-020). Hereafter referred to as the SBF Economic Analysis,
this document presents the analysis of compliance costs and/or savings;
facility closures; changes in rate of return level. In addition,
impacts on employment and affected communities, foreign trade, specific
demographic groups, and new sources also are considered.
3. ``Environmental Assessment of Proposed 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-98-019). Hereafter referred to as the SBF
Environmental Assessment, the document presents the analysis of
relative 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
[[Page 5489]]
column concentrations, pore water concentrations, and human health
effects via consumption of affected seafood.
All documents are available from the Office of Water Resource
Center, RC-4100, U.S. EPA, 401 M Street SW, Washington, DC 20460;
telephone (202) 260-7786 for the voice mail publication request. The
Development Document can also be obtained through EPA's Home Page on
the Internet, located at WWW.EPA.GOV/OST/GUIDE. The preamble and rule
can also be obtained at this site.
Overview
This preamble includes a description of the legal authority for
these rules; a summary of the proposal; background information on the
industry and its processes; and a description of the technical and
economic methodologies used by EPA to develop these regulations. This
preamble also solicits comment and data on all aspects of this proposed
rule. The definitions, acronyms, and abbreviations used in this notice
are defined in Appendix A to the preamble.
Organization of This Document
I. Legal Authority
II. Purpose and Summary of the Proposed Regulation
A. Purpose of this Rulemaking
B. Summary of the Proposed SBF Regulations
III. Background
A. Clean Water Act
B. Permits
C. Pollution Prevention Act
IV. Description of Well Drilling Process and Activity
A. Well Drilling Process Description
B. Location and Activity
C. Drilling Waste Streams
V. Summary of Data Collection Activities
A. Expedited Guidelines Approach
B. Identification of Information Needs
C. Stakeholder Technical Input
D. EPA Research on Toxicity, Biodegradation, Bioaccumulation
E. EPA Investigation of Solids Control Technologies for Drilling
Fluids
F. Assistance from Other State and Federal Agencies
VI. Development of Effluent Limitations Guidelines and Standards
A. Waste Generation and Characterization
B. Selection of Pollutant Parameters
C. Regulatory Options Considered for SBFs Not Associated with
Drill Cuttings
D. Regulatory Options Considered for SBFs Associated with Drill
Cuttings
E. BPT Technology Options Considered and Selected
F. BCT Technology Options Considered and Selected
G. BAT Technology Options Considered and Selected
H. NSPS Technology Options Considered and Selected
VII. Non-Water Quality Environmental Impacts of Proposed Regulations
A. Introduction and Summary
B. Method Overview
C. Energy Consumption and Air Emissions for Existing Sources
D. Energy Consumption and Air Emissions for New Sources
E. Solid Waste Generation and Management
F. Consumptive Water Use
G. Safety
H. Increased Vessel Traffic
VIII. Water Quality Environmental Impacts of Proposed Regulations
A. Introduction
B. Types of Impacts
C. Water Quality Modeling
D. Human Health Effects Modeling
E. Future Seabed Surveys
IX. Costs and Pollutant Reductions Achieved by Regulatory
Alternatives
A. Introduction
B. Model Wells and Well Counts
C. Method for Estimating Compliance Costs
D. Method for Estimating Pollutant Reductions
E. BCT Cost Test
X. Economic Analysis
A. Introduction and Profile of Affected Industry
B. Costs and Costs Savings of the Regulatory Options
C. Impacts from BAT Options
D. Impacts from NSPS Options
E. Cost Benefit Analysis
F. Small Business Analysis
G. Cost-Effective Analysis
XI. Related Acts of Congress, Executive Orders, and Agency
Initiatives
A. Executive Order 12866: OMB Review
B. Regulatory Flexibility Act and the Small Business Regulatory
Enforcement Fairness Act
C. Unfunded Mandates Reform Act
D. Executive Order 12875: Enhancing Intergovernmental
Partnerships
E. Executive Order 13084: Consultation and Coordination with
Indian Tribal Governments
F. Paperwork Reduction Act
G. National Technology Transfer and Advancement Act
H. Executive Order 13045: Children's Health Protection
XII. Regulatory Implementation
A. Analytical Methods
B. Diesel Prohibition for SBF-Cuttings
C. Monitoring of Stock Base Fluid
D. Upset and Bypass Provisions
E. Variances and Modifications
F. Best Management Practices
G. Sediment Toxicity and Biodegradation Comparative Limitations
XIII. Solicitation of Data and Comments
A. Introduction and General Solicitation
B. Specific Data and Comment Solicitations
Appendix A: Definitions, Acronyms, and Abbreviations Used in This
Notice
I. Legal Authority
These regulations are proposed 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.
II. Purpose and Summary of the Proposed Regulation
A. Purpose of This Rulemaking
The purpose of this rulemaking is to amend the effluent limitations
guidelines and standards for the control of discharges of certain
pollutants associated with the use of synthetic-based drilling fluids
(SBFs) and other non-aqueous drilling fluids in portions of the
Offshore Subcategory and Cook Inlet portion of the Coastal Subcategory
of the Oil and Gas Extraction Point Source Category. The limitations
proposed today apply to wastes generated when oil and gas wells are
drilled using SBFs or other non-aqueous drilling fluids (henceforth
collectively referred to simply as SBFs) in coastal and offshore
regions in locations where drilling wastes may be discharged. The
processes and operations that comprise the offshore and coastal oil and
gas subcategories are currently regulated under 40 CFR Part 435,
Subparts A (offshore) and D (coastal). EPA is proposing these
amendments under the authority of the CWA, as discussed in Section I of
this notice. The regulations are also being proposed pursuant to a
Consent Decree entered in NRDC et al. v. Browner, (D.D.C. No. 89-2980,
January 31, 1992) and are consistent with EPA's latest Effluent
Guidelines Plan under section 304(m) of the CWA. (See 63 FR 47285,
September 4, 1998.) The most recent existing effluent limitations
guidelines were issued on March 4, 1993 (58 FR 12454) for the Offshore
Subcategory and on December 16, 1996 (61 FR 66086) for the Coastal
Subcategory. This proposed rule is referred to as the Synthetic-Based
Drilling Fluids Guidelines, or SBF Guidelines, throughout this
preamble.
Today's proposal presents EPA's preferred technology approach and
several others that are being considered in the regulation development
process. The proposed rule is based on a detailed evaluation of the
available data acquired during the development of the proposed
limitations. EPA welcomes comment on all options and issues and
encourages commenters to submit additional data during the comment
period. Also, EPA is willing to meet with interested parties during the
comment period to ensure that EPA has the views of all parties and the
best possible data upon which to base a decision for the final
regulation. EPA emphasizes that it is soliciting comments on all
options discussed in this proposal and that it may adopt any
[[Page 5490]]
such options or combination of options in the final rule.
B. Summary of Proposed SBF Guidelines
This summary section highlights key aspects of the proposed rule.
The technology descriptions discussed later in this notice are
presented in abbreviated form; more detailed descriptions are included
in the Development Document for Proposed Effluent Limitations
Guidelines and Standards for Synthetic-Based and other Non-Aqueous
Drilling Fluids in the Oil and Gas Extraction Point Source Category,
referred to hereafter as the ``SBF Development Document.''
EPA proposes to establish regulations based on the ``best
practicable control technology currently available'' (BPT), ``best
conventional pollutant control technology'' (BCT), ``best available
technology economically achievable'' (BAT), and the best available
demonstrated control technology (BADCT) for new source performance
standards (NSPS), for the wastestream of synthetic-based drilling
fluids and other non-aqueous drilling fluids, and cuttings contaminated
with these drilling fluids.
For certain drilling situations, such as drilling in reactive
shales, high angle and/or high displacement directional drilling, and
drilling in deep water, progress with water-based drilling fluids
(WBFs) can be slow, costly, or even impossible, and often creates a
large amount of drilling waste. In these situations, the well is
normally drilled with traditional oil-based drilling fluids (OBFs),
which use diesel oil or mineral oil as the base fluid. Because EPA
rules require zero discharge of these wastes, they are either sent to
shore for disposal in non-hazardous oil field waste (NOW) sites or
injected into disposal wells.
Since about 1990, the oil and gas extraction industry has developed
many new oleaginous (oil-like) base materials from which to formulate
high performance drilling fluids. A general class of these are called
the synthetic materials, such as the vegetable esters, poly alpha
olefins, internal olefins, linear alpha olefins, synthetic paraffins,
ethers, linear alkyl benzenes, and others. Other oleaginous materials
have also been developed for this purpose, such as the enhanced mineral
oils and non-synthetic paraffins. Industry developed SBFs with these
synthetic and non-synthetic oleaginous materials as the base fluid to
provide the drilling performance characteristics of traditional OBFs
based on diesel and mineral oil, but with lower environmental impact
and greater worker safety through lower toxicity, elimination of
polynuclear aromatic hydrocarbons (PAHs), faster biodegradability,
lower bioaccumulation potential, and, in some drilling situations, less
drilling waste volume. EPA believes that this product substitution
approach is an excellent example of pollution prevention that can be
accomplished by the oil and gas industry.
EPA intends that these proposed regulations control the discharge
of SBFs in a way that reflects application of appropriate levels of
technology, while also encouraging their use as a replacement to the
traditional mineral oil and diesel oil-based fluids. Based on EPA's
information to date, the record indicates that use of SBFs and
discharge of the cuttings waste with proper controls would overall be
environmentally preferable to the use of OBFs. This is because OBFs are
subject to zero discharge requirements, and thus, must be shipped to
shore for land disposal or injected underground, resulting in higher
air emissions, increased energy use, and increased land disposal of
oily wastes. By contrast, the discharge of cuttings associated with
SBFs would eliminate those impacts. At the same time EPA recognizes
that the discharge of SBFs may have impacts to the receiving water.
Because SBFs are water non-dispersible and sink to the seafloor, the
primary potential environmental impacts are associated with the benthic
community. EPA's information to date, including limited seabed surveys
in the Gulf of Mexico, indicate that the effect zone of the discharge
of certain SBFs is within a few hundred meters of the discharge point
and may be significantly recovered in one to two years. EPA believes
that impacts are primarily due to smothering by the drill cuttings,
changes in sediment grain size and composition (physical alteration of
habitat), and anoxia (absence of oxygen) caused by the decomposition of
the organic base fluid. The benthic smothering and changes in grain
size and composition from the cuttings are effects that are also
associated with the discharge of WBFs and associated cuttings.
Based on the record to date, EPA finds that these impacts, which
are believed to be of limited duration, are less harmful to the
environment than the non-water quality environmental impacts associated
with the zero discharge requirement applicable to OBFs. Compared to the
zero discharge option EPA estimates that allowing discharge will reduce
air emissions of the criteria air pollutants by 450 tons per year,
decrease fuel use by 29,000 barrels per year of oil equivalent, and
reduce the generation of oily drill cutting wastes requiring off-site
disposal by 212 million pounds per year. In addition, EPA estimates
that compliance with these proposed limitations would result in a
yearly decrease in the discharge of 11.7 million pounds of toxic and
nonconventional pollutants in the form of SBFs. These estimates are
based on the current industry practice of discharging SBF-cuttings
outside of 3 miles in the Gulf of Mexico and no discharge of SBFs in
any other areas, including 3 miles offshore of California and in Cook
Inlet, Alaska.
As SBFs came into commercial use, EPA determined that the current
discharge monitoring methods, which were developed to control the
discharge of WBFs, did not appropriately control the discharge of these
new drilling fluids. Since WBFs disperse in water, oil contamination of
WBFs with formation oil or other sources can be measured by the static
sheen test, and any toxic components of the WBFs will disperse in the
aqueous phase and be detected by the suspended particulate phase (SPP)
toxicity test. With SBFs, which do not disperse in water but instead
sink as a mass, formation oil contamination has been shown to be less
detectible by the static sheen test. Similarly, the potential toxicity
of the discharge is not apparent in the current SPP toxicity test.
EPA has therefore sought to identify methods to control the
discharge of cuttings associated with SBFs (SBF-cuttings) in a way that
reflects the appropriate level of technology. One way to do this is
through stock limitations on the base fluids from which the drilling
fluids are formulated. This would ensure that substitution of synthetic
and other oleaginous base fluids for traditional mineral oil and diesel
oil reflects the appropriate level of technology. In other words, EPA
wants to ensure that only the SBFs formulated from the ``best'' base
fluids are allowed for discharge. Parameters that distinguish the
various base fluid are the polynuclear aromatic hydrocarbon (PAH)
content, sediment toxicity, rate of biodegradation, and potential for
bioaccumulation.
EPA also thinks that the SBF-cuttings should be controlled with
discharge limitations, such as a limitation on the toxicity of the SBF
at the point of discharge, and a limitation on the mass (as volume) or
concentration of SBFs discharged. The latter type of limitation would
take advantage of the solids separation efficiencies achievable with
SBFs, and consequently minimize the
[[Page 5491]]
discharge of organic and toxic components. EPA believes that SBFs
separated from drill cuttings should meet zero discharge requirements,
as this is the current industry practice due to the value of these
drilling fluids.
Thus, EPA is proposing limits appropriate to SBF-cuttings. EPA is
proposing zero discharge of neat SBFs (not associated with cuttings),
which reflects current practice. The new limitations applicable to
cuttings contaminated with SBFs would be as follows:
Stock Limitations on Base Fluids: (BAT/NSPS).
Maximum PAH content 10 ppm (wt. based on phenanthrene/wt.
base fluid).
Minimum rate of biodegradation (biodegradation equal to or
faster than C16-C18 internal olefin by solid
phase test).
Maximum sediment toxicity (as toxic or less toxic than
C16-C18 internal olefin by 10-day sediment
toxicity test).
Discharge Limitations on Cuttings Contaminated with SBFs:
No free oil by the static sheen test. (BPT/BCT/NSPS).
Maximum formation oil contamination (95 percent of
representative formation oils failing 1 percent by volume in drilling
fluid). (BAT/NSPS).
Maximum well-average retention of SBF on cuttings (percent
base fluid on wet cuttings). (BAT/NSPS).
Discharges remain subject to the following requirements already
applicable to all drilling waste discharges and thus these requirements
are not within the scope of this rulemaking:
Mercury limitation in stock barite of 1 mg/kg. (BAT/NSPS).
Cadmium limitation in stock barite of 3 mg/kg. (BAT/NSPS).
Diesel oil discharge prohibition. (BAT/NSPS).
EPA may require these additional or alternative controls as part of
the discharge option based on method development and data gathering
subsequent to today's notice:
Maximum sediment toxicity of drilling fluid at point of
discharge (minimum LC50, mL drilling fluid/kg dry sediment
by 10-day sediment toxicity test or amended test). (BAT/NSPS).
Maximum aqueous phase toxicity of drilling fluid at point
of discharge (minimum LC50 by SPP test or amended SPP test).
(BAT/NSPS).
Maximum potential for bioaccumulation of stock base fluid
(maximum concentration in sediment-eating organisms). (BAT/NSPS).
EPA is also considering a zero discharge option in the event that
EPA has an insufficient basis upon which to develop appropriate
discharge controls for SBF-cuttings:
Zero discharge of drill cuttings contaminated with SBFs
and other non-aqueous drilling fluids. (BPT/BCT/BAT/NSPS).
While EPA is proposing limitations on these parameters today, many
of the test methods that would be used to demonstrate attainment with
the limitations are still under development at this time, or additional
data needs to be gathered towards validating methods, proving the
variability and appropriateness of the methods, and assessing
appropriate limitations for the parameters. For example, as noted in
the list above, EPA is considering limitations in addition, or as an
alternative, to the limitations in today's proposal. The reason for
this is that EPA has insufficient data at this time to determine how to
best control toxicity and whether a bioaccumulation limitation is
necessary to adequately control the SBF-cuttings wastestream.
EPA would prefer to control sediment toxicity at the point of
discharge. While there is an EPA approved sediment toxicity test to do
this, EPA has concerns about the uniformity of the sediment used in the
toxicity test, the discriminatory power and variability of the test so
applied. Since the test is 10 days long, it poses a practical problem
for operators who would prefer to know immediately whether cuttings may
be discharges. Applying EPA's existing sediment toxicity test to the
base fluid as a stock limitation ameliorates these concerns, such that,
at this stage of the development of the test, EPA thinks that it is
more likely to be practically applied. As this would be the preferred
method of control, EPA intends to continue research into the test as
applied to the drilling fluid at the point of discharge. Industry also
has been conducting research to develop a sediment toxicity test that
may be applied to SBFs at the point of discharge with the cuttings.
Further, EPA intends to perform research into the aquatic toxicity test
to see if it can be used to adequately control the discharge through
modification. EPA may then consider applying an aqueous phase toxicity
test, either alone or in conjunction with a sediment toxicity test of
either the stock base fluid or drilling fluid at the point of
discharge.
In terms of the retention of SBF on cuttings, while EPA has enough
information to propose a limitation, EPA is still evaluating methods to
determine attainment of this limit. For the parameter of
biodegradation, EPA is proposing a numerical limit, but the analytic
method for measuring attainment of the limit has not yet been
validated. EPA wishes to do additional studies to validate the method
and provide public notice of any subsequently developed numerical
limit.
Because EPA plans to gather significant additional information in
support of the final rule, EPA intends to publish a supplemental notice
for public comment providing the proposed limitations and specific test
methods. These data gathering activities are summarized in Section V of
today's notice. Section VI details the information gathered to support
this selection of parameters, and the further information that EPA
intends to gather to support the methods and limitations for the
intended notice and subsequent final rule.
Therefore, the purpose of today's proposal is to request comment on
the candidate requirements listed above, identify the additional work
that EPA intends to perform towards promulgation of the limitations,
and request comments and additional data towards the selection of
parameters, methods and limitations development. EPA also intends that
this proposal serve as guidance to permit writers such that the
proposed methods can be incorporated into permits through best
professional judgement (BPJ). Such permits can be used to gather
supporting information towards selection of parameters, methods
development, and appropriate limitations.
The current regulations establish the geographic areas where
drilling wastes may be discharged: the offshore subcategory waters
beyond 3 miles from the shoreline, and in Alaska offshore waters with
no 3-mile restriction. The only coastal subcategory waters where
drilling wastes may be discharged is in Cook Inlet, Alaska. EPA is
retaining the zero discharge limitations in areas where discharge is
currently prohibited and these requirements are not within the scope of
this rulemaking.
EPA is limiting the scope of today's proposed rulemaking to
locations where drilling wastes may be discharged because these are the
only locations for which EPA has evaluated the non-water quality
environmental impacts of zero discharge versus the environmental
impacts of discharging drill cuttings associated with SBFs. For
example, EPA has only assessed the non-water quality environmental
impacts of zero discharge beyond three miles from shore. EPA expects
these impacts to be less where
[[Page 5492]]
the wastes are generated closer to shore. In addition, EPA has not
assessed the environmental effects of these discharges in coastal
areas. The current zero discharge areas are more likely to be
environmentally sensitive due to the presence of spawning grounds,
wetlands, lower energy (currents), and more likely to be closer to
recreational swimming and fishing areas. Further, dischargers are in
compliance with the zero discharge requirement and have only expressed
an interest in the use of these newer fluids where drilling wastes may
be discharged today.
III. Background
A. Clean Water Act
1. Summary of Effluent Limitations Guidelines and Standards
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 limitation guidelines
and new source performance standards in National Pollutant Discharge
Elimination System (``NPDES'') permits; indirect dischargers must
comply with pretreatment standards. EPA issues these guidelines and
standards for categories of industrial dischargers based on the degree
of control that can be achieved using various levels of pollution
control technology. The guidelines and standards are summarized below:
a. Best Practicable Control Technology Currently Available (BPT)--
sec. 304(b)(1) of the CWA.--Effluent limitations guidelines based on
BPT apply to discharges of conventional, toxic, and non-conventional
pollutants from existing sources. BPT guidelines are generally based on
the average of the best existing performance by plants in a category or
subcategory. In establishing BPT, EPA considers the cost of achieving
effluent reductions in relation to the effluent reduction benefits, the
age of equipment and facilities, the processes employed, process
changes required, engineering aspects of the control technologies, non-
water quality environmental impacts (including energy requirements),
and other factors the EPA Administrator deems appropriate. CWA
Sec. 304(b)(1)(B). Where existing performance is uniformly inadequate,
BPT may be transferred from a different subcategory or category.
b. Best Conventional Pollutant Control Technology (BCT)--sec.
304(b)(4) of the CWA.--The 1977 amendments to the CWA established BCT
as an additional level of control for discharges of conventional
pollutants from existing industrial point sources. In addition to other
factors specified in section 304(b)(4)(B), the CWA requires that BCT
limitations be established in light of a two part ``cost-
reasonableness'' test. EPA published a methodology for the development
of BCT limitations which became effective August 22, 1986 (51 FR 24974,
July 9, 1986).
Section 304(a)(4) designates the following as conventional
pollutants: biochemical oxygen demanding pollutants (measured as
BOD5), total suspended solids (TSS), fecal coliform, pH, and
any additional pollutants defined by the Administrator as conventional.
The Administrator designated oil and grease as an additional
conventional pollutant on July 30, 1979 (44 FR 44501).
c. Best Available Technology Economically Achievable (BAT)--sec.
304(b)(2) of the CWA.--In general, BAT effluent limitations guidelines
represent the best available economically achievable performance of
plants in the industrial subcategory or category. The CWA establishes
BAT as a principal national means of controlling the direct discharge
of toxic and nonconventional pollutants. The factors considered in
assessing BAT include the age of equipment and facilities involved, the
process employed, potential process changes, non-water quality
environmental impacts, including energy requirements, and such factors
as the Administrator deems appropriate. The Agency retains considerable
discretion in assigning the weight to be accorded these factors. An
additional statutory factor considered in setting BAT is economic
achievability across the subcategory. Generally, the achievability is
determined on the basis of total costs to the industrial subcategory
and their effect on the overall industry (or subcategory) financial
health. As with BPT, where existing performance is uniformly
inadequate, BAT may be transferred from a different subcategory or
category. BAT may be based upon process changes or internal controls,
such as product substitution, even when these technologies are not
common industry practice. The CWA does not require a cost-benefit
comparison in establishing BAT.
d. New Source Performance Standards (NSPS)--section 306 of the
CWA.--NSPS are based on the best available demonstrated control
technology (BADCT) and apply to all pollutants (conventional,
nonconventional, and toxic). NSPS are at least as stringent as BAT. New
plants have the opportunity to install the best and most efficient
production processes and wastewater treatment technologies. Under NSPS,
EPA is to consider the best demonstrated process changes, in-plant
controls, and end-of-process control and treatment technologies that
reduce pollution to the maximum extent feasible. In establishing NSPS,
EPA is directed to take into consideration the cost of achieving the
effluent reduction and any non-water quality environmental impacts and
energy requirements.
e. Pretreatment Standards for Existing Sources (PSES)--sec. 307(b)
of the CWA--and Pretreatment Standards for New Sources (PSNS)--sec.
307(b) of the CWA.--Pretreatment standards are designed to prevent the
discharge of pollutants to a publicly-owned treatment works (POTW)
which pass through, interfere, or are otherwise incompatible with the
operation of the POTW. Since none of the facilities to which this rule
applies discharge to a POTW, pretreatment standards are not being
considered as part of this rulemaking.
f. Best Management Practices (BMPs).--Section 304(e) of the CWA
gives the Administrator the authority to publish regulations, in
addition to the effluent limitations guidelines and standards listed
above, to control plant site runoff, spillage or leaks, sludge or waste
disposal, and drainage from raw material storage which the
Administrator determines may contribute significant amounts of toxic
and hazardous pollutants to navigable waters. Section 402(a)(1) also
authorizes best management practices (BMPs) as necessary to carry out
the purposes and intent of the CWA. See 40 CFR Part 122.44(k).
g. 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 (i) reviewing and revising existing effluent limitations
guidelines and standards and (ii) promulgating new effluent guidelines.
On January 2, 1990, EPA published an Effluent Guidelines Plan (55 FR
80), in which schedules were established for developing new and revised
effluent guidelines for several industry
[[Page 5493]]
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 September 4, 1998 (63 FR 47285). This plan
requires, among other things, that EPA propose the Synthetic-Based
Drilling Fluids Guidelines by 1998 and promulgate the Guidelines by
2000.
2. Prior Federal Rulemakings and Other Notices
On March 4, 1993, EPA issued final effluent guidelines for the
Offshore Subcategory of the Oil and Gas Extraction Point Source
Category (58 FR 12454). The data and information gathering phase for
this rulemaking thus corresponded to the introduction of SBFs in the
Gulf of Mexico. Because of this timing, the range of drilling fluids
for which data and information were available to EPA was limited to
water-based drilling fluids (WBFs) and oil-based drilling fluids (OBFs)
using diesel and mineral oil. Industry representatives, however,
submitted information on SBFs during the comment period concerning
environmental benefits of SBFs over OBFs and WBFs, and problems with
false positives of free oil in the static sheen test applied to SBFs.
The requirements in the offshore rule applicable to drilling fluids
and drill cuttings consist of mercury and cadmium limitations on the
stock barite, a diesel oil discharge prohibition, a toxicity limitation
on the suspended particulate phase (SPP) generated when the drilling
fluids or drill cuttings are mixed in seawater, and no discharge of
free oil as determined by the static sheen test.
While the SPP toxicity test and the static sheen test, and their
limitations, were developed for use with WBF, the offshore regulation
does not specify the types of drilling fluids and drill cuttings to
which these limitations apply. Thus, under the rule, any drilling waste
in compliance with the discharge limitations could be discharged. When
the offshore rule was proposed, EPA believed that all drilling fluids,
be they WBFs, OBFs, or SBFs, could be controlled by the SPP toxicity
and static sheen tests. This is because OBFs based on diesel oil or
mineral oil failed one or both of the SPP toxicity test and no free oil
static sheen test. In addition, OBFs based on diesel oil were subject
to the diesel oil discharge prohibition.
EPA thought SBFs could also be adequately controlled by the
regulation based on comments received from industry. After the offshore
rule was proposed, EPA received several industry comments which focused
on the fact that the static sheen test could often be interpreted as
giving a false positive for the presence of diesel oil, mineral oil, or
formation hydrocarbons. For this reason, the industry commenters
contended that SBFs should be exempt from compliance with the no free
oil limitation required by the proposed offshore effluent guidelines.
In the final rulemaking in 1993, EPA's response to these comments
was that the prohibition on discharges of free oil was an appropriate
limitation for discharge of drill fluids and drill cuttings, including
SBFs. While EPA agreed that some of the newer SBFs may be less toxic
and more readily biodegradable than many of the OBFs, EPA was concerned
that no alternative method was offered for determining compliance with
the no free oil standard to replace the static sheen test. In other
words, if EPA were to exclude certain fluids from the requirement,
there would be no way to determine if at that particular facility,
diesel oil, mineral oil or formation hydrocarbons were also being
discharged.
Also in the final offshore rule, EPA encouraged the use of drilling
fluids that were less toxic and biodegraded faster. EPA solicited data
on alternative ways of monitoring for the no free oil discharge
requirement, such as gas chromatography or other analytical methods.
EPA also solicited information on technology issues related to the use
of SBFs, any toxicity data or biodegradation data on these newer
fluids, and cost information.
By focusing on the issue of false positives with the static sheen
test, EPA interpreted the offshore effluent guidelines to mean that
SBFs could be discharged provided they complied with the current
discharge requirements. EPA did not think, however, that many, if any,
SBFs would be able to meet the no free oil requirement.
In the final coastal effluent guidelines, EPA raised the issue of
false negatives with the static sheen test as opposed to the issue of
false positives raised during the offshore rulemaking. EPA had
information indicating that the static sheen test does not adequately
detect the presence of diesel, mineral, or formation oil in SBFs. In
addition, EPA raised other concerns regarding the inadequacy of the
current effluent guidelines to control of SBF wastestreams. Thus the
final coastal effluent guidelines, published on December 16, 1996 (61
FR 66086), constitute the first time EPA identified, as part of a
rulemaking, the inadequacies of the current regulations and the need
for new BPT, BAT, BCT, and NSPS controls for discharges associated with
SBFs.
The coastal rule adopted the offshore discharge requirements to
allow discharge of drilling wastes in one geographic area of the
coastal subcategory; Cook Inlet, Alaska, and prohibited the discharge
of drilling wastes in all other coastal areas.
Due to the lack of information concerning appropriate controls, EPA
could not provide controls specific to SBFs as a part of the coastal
rule. However, the coastal rulemaking solicited comments on SBFs. In
responding to these comments, EPA again identified certain
environmental benefits of using SBFs, and stated that allowing the
controlled discharge of SBF-cuttings would encourage their use in place
of OBFs. EPA also raised the inadequacies of the current effluent
guidelines to control the SBF wastestreams, and provided an outline of
the parameters which EPA saw as important for adequate control. The
inadequacies cited include the inability of the static sheen test to
detect formation oil or other oil contamination in SBFs and the
inability of the SPP toxicity test to adequately measure the toxicity
of SBFs. EPA offered alternative tests of gas chromatography (GC) and a
benthic toxicity test to verify the results of the static sheen and the
suspended particulate phase (SPP) toxicity testing currently required.
EPA also mentioned the potential need for controls on the base fluid
used to formulate the SBF, based on one or more of the following
parameters: PAH content, toxicity (preferably sediment toxicity), rate
of biodegradation, and bioaccumulation potential.
The final coastal rule also incorporated clarifying definitions of
drilling fluids for both the offshore and coastal subcategories to
better differentiate between the types of drilling fluids. The rule
provided guidance to permit writers needing to write limits for SBFs on
a best professional judgement (BPJ) basis as using GC as a confirmation
tool to assure the absence of free oil in addition to meeting the
current no free oil (static sheen), toxicity, and barite limits on
mercury and cadmium. EPA
[[Page 5494]]
recommended Method 1663 as described in EPA 821-R-92-008 as a gas
chromatograph with flame ionization detection (GC/FID) method to
identify an increase in n-alkanes due to crude oil contamination of the
synthetic materials coating the drill cuttings. Additional tests, such
as benthic toxicity conducted on the synthetic material prior to use or
whole SBF prior to discharge, were also suggested for controlling the
discharge of cuttings contaminated with drilling fluid.
EPA stated intentions to evaluate further the test methods for
benthic toxicity and determine an appropriate limitation if this
additional test is warranted. In addition, test methods and results for
bioaccumulation and biodegradation, as indications of the rate of
recovery of the cuttings piles on the sea floor, were to be evaluated.
EPA recognized that evaluations of such new testing protocols may be
beyond the technical expertise of individual permit writers, and so
stated that these efforts would be coordinated as a continuing effluent
guidelines effort. Today's proposal is a result of these efforts.
B. Permits
Four EPA Regions currently issue or review permits for offshore and
coastal oil and gas well drilling activities in areas where drilling
wastes may be discharged: Region 4 in the Eastern Gulf of Mexico (GOM),
Region 6 in the Central and Western GOM, Region 9 in offshore
California, and Region 10 in offshore and Cook Inlet, Alaska. Permits
in Regions 4, 9 and 10 never allowed the discharge of SBFs, and those
three Regions are currently preparing final general permits that either
specifically disallow SBF discharges until adequate discharge controls
are available to control the SBF wastestreams, or allow a limited use
of SBF to facilitate information gathering.
Discharge of drill cuttings contaminated with SBF (SBF-cuttings)
has occurred under the Region 6 offshore continental shelf (OCS)
general permit issued in 1993 (58 FR 63964), and the general permit
reissued on November 2, 1998 (63 FR 58722) again does not specifically
disallow the continued discharge of SBF-cuttings. The reason for these
differences between Region 6 and the other EPA Regions relates to the
timing of the 1993 Region 6 general permit and the issues raised in
comments during the issuance of that permit.
The previous individual and general permits of Regions 4, 9 and 10
were issued long before SBFs were developed and used. In Region 6,
however, the first SBF well was drilled in June of 1992 and the
development of the Region 6 OCS general permit, published December 3,
1993 (58 FR 63964), thus corresponded to the introduction of SBF use in
the GOM. After proposal of this permit, industry representatives
commented that the no free oil limitation as measured by the static
sheen test should be waived for SBFs, due to the occurrence of false
positives. They contended that a sheen was sometimes perceived when the
SBF was known to be free of diesel oil, mineral oil or formation oil.
These comments were basically the same as those submitted as part of
the offshore rulemaking, which occurred in the same time frame. EPA
responded as it had in the offshore rulemaking, maintaining the static
sheen test until there existed a replacement test to determine the
presence of free oil. EPA stated that if the current discharge
requirements could be met then the drilling fluid and associated wastes
could be discharged. This response indicated EPA's position that SBF
drilling wastes could be discharged as long as the discharge met permit
requirements. But again, in the context of these comments, EPA did not
expect that many, if any SBFs, would be able to meet the static sheen
requirements.
In addition to the requirements of the offshore guidelines, the
Region 6 OCS general permit also prohibited the discharge of oil-based
and inverse emulsion drilling fluids. Although SBFs are, in chemistry
terms, inverse emulsion drilling fluids, the definition in the permit
limited the term ``inverse emulsion drilling fluids'' to mean ``an oil-
based drilling fluid which also contains a large amount of water.''
Further, the permit provides a definition for oil-based drilling fluid
as having ``diesel oil, mineral oil, or some other oil as its
continuous phase with water as the dispersed phase.'' Since the SBFs
clearly do not have diesel or mineral oil as the continuous phase,
there was a question of whether synthetic base fluids (and more
broadly, other oleaginous base fluids) used to formulate the SBFs are
``some other oil.'' With consideration of the intent of the inverse
emulsion discharge prohibition, and the known differences in
polynuclear aromatic hydrocarbon content, toxicity, and biodegradation
between diesel and mineral oil versus the synthetics, EPA determined
that SBFs were not inverse emulsion drilling fluids as defined in the
Region 6 general permit. This determination is exemplified by the
separate definitions for OBFs and SBFs introduced with the Coastal
Effluent Guidelines (see 61 FR 66086, December 16, 1996).
In late 1998 and early 1999, all four Regions are (re)issuing their
general permits for offshore (Regions 4, 6 and 9) and coastal (Region
10) oil and gas wells. Once the effluent guidelines or guidance becomes
available, EPA intends to reopen the permits to add requirements that
adequately control SBF drilling wastes.
EPA intends for today's proposal to act as guidance such that the
Regions do not have to wait until issuance of a final rule planned for
December 2000, but may propose to add the appropriate discharge
controls through best professional judgement (BPJ). In this manner, the
controlled discharge of SBF may be used to further aid EPA in gathering
information subsequent to today's proposal.
C. Pollution Prevention Act
The Pollution Prevention Act of 1990 (PPA) (42 U.S.C. 13101 et
seq., Pub. L. 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
[[Page 5495]]
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 this proposed rule, EPA supports pollution prevention technology
by encouraging the use of SBFs based on certain synthetic materials and
other similarly performing materials in place of traditional oil-based
drilling fluids based on diesel oil and mineral oil. The waste
generated from SBFs is anticipated to have lower toxicity, lower
bioaccumulation potential, faster biodegradation, and elimination of
polynuclear aromatic hydrocarbons, including those which are priority
pollutants. With these improved characteristics, and to encourage their
use in place of OBFs, EPA is proposing to allow the controlled on-site
discharge of the cuttings associated with SBF. Use of SBF in place of
OBF will eliminate the need to barge to shore or inject oily waste
cuttings, reducing fuel use, air emissions, and land disposal. It also
eliminates the risk of OBF and OBF-cuttings spills. In addition, the
proposed regulatory option includes efficient closed-loop recycling
systems to reduce the quantity of SBF discharged with the drill
cuttings. A discussion of this pollution prevention technology is
contained in Section VI of this notice and in the Development Document.
IV. Description of Process and Well Drilling Activities
A. Well Drilling Process Description
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. 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 as much fluid from the cuttings
as possible. 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. Drill cuttings are also cleaned out of the
mud pits and from the solid separation equipment during displacement of
the drilling fluid system. 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 deepwater drilling, generally greater
than 3000' water depth, new drilling methods are evolving which can
significantly improve drilling efficiencies and thereby reduce the
volume of drilling fluid discharges as well as reduce non-water quality
effects of fuel and steel consumption and air emissions. Subsea
drilling fluid boosting, referred to as ``subsea pumping'', is one such
technology. Rotary drilling methods are generally performed as
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.
Wells are drilled in less time, including less trouble time. To enable
the pumping of drilling fluids and cuttings to the surface, some drill
cuttings, larger than approximately one-fourth of an inch, are
separated from the drilling fluid at the seafloor since these cuttings
cannot reliably be pumped to the surface. The drill cuttings which are
separated at the seafloor are discharged through an eductor hose at the
seafloor within a 300' radius of the well site. For purposes of
monitoring, representative samples of drill cuttings discharged at the
seafloor can be transported to the surface and separated from the
drilling fluid in a manner similar to that employed at the seafloor.
The drilling fluid, which is boosted at the seafloor and transports
most of the drill cuttings back to the surface, is processed as
described in the general rotary drilling methods described above in
this section.
Once the target formations have been reached, and a determination
made as to which have commercial potential, the well is made ready for
production by a process termed ``completion.'' Completion involves
cleaning the well to remove drilling fluids and debris, 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, or actual
extraction of hydrocarbons.
B. Location and Activity
This proposed regulation would establish discharge limitations for
SBFs in areas where drilling fluids and drill cuttings are allowed for
discharge. These discharge areas are the offshore waters beyond 3 miles
from shore except the offshore waters of Alaska which has no 3 mile
discharge restriction, and the coastal waters of Cook Inlet, Alaska.
Drilling is currently active in three regions in these discharge areas:
(i) the offshore waters beyond three miles from shore in the Gulf of
Mexico (GOM), (ii) offshore waters beyond three miles from shore in
California, and (iii) the coastal waters of Cook Inlet, Alaska.
Offshore Alaska is the only other area where drilling is active and
effluent guidelines allows discharge. However, drilling wastes are not
currently discharged in the Alaska offshore waters.
Among these three areas, 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
the deepwater, defined as water greater than 1,000 feet deep. For
example, in 1995, 84 wells were drilled in the deepwater, comprising
8.6 percent of all GOM wells drilled that year. By 1997, that number
increased to 173 wells drilled and comprised over 13 percent of all GOM
[[Page 5496]]
wells drilled. The increased activity in the deepwater increases the
usefulness of SBFs. Operators drilling in the deepwater cite the
potential for riser disconnect in floating drill ships, which favors
SBF over OBF; higher daily drilling cost which more easily justifies
use of more expensive SBFs over WBFs; and greater distance to barge
drilling wastes that may not be discharged (i.e., OBFs).
C. Drilling Wastestreams
Drilling fluids and drill cuttings are the most significant
wastestreams from exploratory and development well drilling operations.
This rule proposes limitations for the drilling fluid and cuttings
wastestream resulting when SBFs or other non-aqueous drilling fluids
are used. All other wastestreams and drilling fluids have current
applicable limitations which are outside the scope of this rulemaking.
A summary of the characteristics of these wastes is presented in
Section VI of this notice. A more detailed discussion of the origins
and characteristics of these wastes is included in the Development
Document.
V. Summary of Data Gathering Efforts
A. Expedited Guidelines Approach
This regulation is being developed using an expedited rulemaking
process. This process relies on stakeholder support to develop the
initial technology and regulatory options. At various stages of
information gathering, industry, EPA and other stakeholders present and
discuss their preferred options and identify differences in opinion.
This proposal, as part of the expedited process, is being presented
today in a shorter developmental time period, and with less information
than a typical effluent guidelines proposal. The proposed rule is then
a tool to identify the candidate requirements, and request comments and
additional data. EPA plans to continue this expedited rulemaking
process of relying on industry, environmental groups, and other
stakeholder support for the further regulatory development after
proposal.
EPA encourages full public participation in developing the final
SBF Guidelines. This expedited rulemaking process succeeds with more
open communication between EPA, the regulated community, and other
stakeholders, and relies less on formal data and information gathering
mechanisms. The expedited guidelines approach is suitable when EPA,
industry, and other stakeholders have a common goal on the structure of
the limitations and standards. EPA believes this is the case with the
SBF rulemaking; EPA is proposing to allow the controlled discharge of
the SBF-cuttings wastestream to encourage the use and further
development of this pollution prevention technology. Based on
information to date, EPA believes that this option has better
environmental results than the current use and subsequent land disposal
or injection of OBFs. Through the exchange of information among the
stakeholders, EPA understands the industry's interest in discharging
the SBF-cuttings wastestream because discharge of SBFs is more likely
to be cost effective as a replacement to the diesel and mineral oil
based OBFs. EPA was able to accommodate both environmental benefits and
business interests in today's proposal.
Throughout regulatory development, EPA has worked with
representatives from the oil and gas industry and several trade
associations, including the National Ocean Industries Association
(NOIA) and the American Petroleum Institute (API), SBF vendors, solids
control equipment vendors, the U.S. Department of Energy, the U.S.
Department of Interior Minerals Management Service, the Texas Railroad
Commission, and research and regulatory bodies of the United Kingdom
and Norway, to develop effluent limitations guidelines and standards
that represent the appropriate level of technology (e.g., BAT). The
Agency also discussed the progress of the rulemaking with the Natural
Resources Defense Council (NRDC) and invited its participation. The
Cook Inlet Keepers are participating in the rulemaking as well.
As part of the expedited approach to this rulemaking, EPA has
chosen not to gather data using the time consuming approach of a Clean
Water Act section 308 questionnaire, but rather by using data submitted
by industry, vendors, academia, and others, along with data EPA can
develop in a limited period of time. Because all of the facilities
affected by this proposal are direct dischargers, the Agency did not
conduct an outreach survey to POTWs.
Subsequent to today's proposal, EPA intends to continue its data
gathering efforts for support of the final rule. These continuing
efforts are discussed below in conjunction with the information already
gathered. Because of these continuing information gathering activities,
EPA expects that it will publish a subsequent notice of any data either
generated by EPA or submitted after this proposal that will be used to
develop the final rule.
B. Identification of Information Needs
As part of the final coastal effluent guidelines, published on
December 16, 1996 (61 FR 66086), EPA stated that appropriate and
adequate discharge controls would be necessary to allow the discharge
of SBF-cuttings under BPT, BAT, BCT, and NSPS in NPDES permits. As
detailed in Section III of today's notice, in the final coastal
effluent guidelines EPA recommended gas chromatography (GC) as a test
for formation oil contamination, and a sediment toxicity test as a
replacement for the suspended particulate phase (SPP) toxicity testing
currently required. EPA also mentioned the potential need for controls
on the base fluid used to formulate the SBF, controlling one or more of
the following parameters: PAH content, toxicity (preferably sediment
toxicity), rate of biodegradation, and bioaccumulation potential. EPA
summarized the information available from seabed surveys at SBF-
cuttings discharge sites.
Subsequent to the publication of the final coastal effluent
guidelines, EPA continued research into the appropriate controls for
the SBF-cuttings wastestream, and presented its findings to
stakeholders at meetings held in Dallas, Texas, on February 19, 1998,
and in Houston on May 8 and 9, 1997. EPA also presented data and
information requirements to develop adequate and appropriate controls
for the SBF-cuttings wastestream at four conferences, in Aberdeen,
Scotland, on June 23 and 24, 1997, in Houston, Texas on February 9,
1998, again in Aberdeen Scotland on June 18 and 19, 1998, and at the
Minerals Management Service Information Transfer Meeting held in New
Orleans, Louisiana on December 18, 1997. The conferences in Scotland
were germane because of the work that the Scottish Office Agriculture,
Environment and Fisheries Department had performed on sediment toxicity
testing, biodegradability testing, and seabed surveys at SBF-cuttings
and OBF-cuttings discharge sites. This detailed level of work has not
been performed in the United States.
EPA conducted literature reviews and in September 1997 published
documents entitled ``Bioaccumulation of Synthetic-Based Drilling
Fluids,'' ``Biodegradation of Synthetic-Based Drilling Fluids,''
``Assessment and Comparison of Available Drilling Waste Data from Wells
Drilled Using Water Based Fluids and Synthetic Based Fluids,'' and
``Seabed Survey Review and Summary.'' The purpose of these documents
was to help direct EPA's and other stakeholder's research efforts in
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defining BPT, BAT, BCT, and NSPS, and address CWA 403(c) requirements
for SBFs.
Industry stakeholders, with the motivation of having SBFs addressed
in NPDES permits that allow the discharge of SBF-cuttings, assisted EPA
in the development of methods and data gathering to describe currently
available technologies. Thus, by means of meetings, conferences, and
other stakeholder meetings, EPA detailed the methods and/or types of
information required in order to support BPT, BCT, BAT, and NSPS
controls in NPDES permits. The past and anticipated future efforts by
various stakeholder groups and the EPA are presented below.
C. Stakeholder Technical Work Groups
In order to concentrate efforts on certain technical issues, in May
of 1997 industry prepared studies on the following subjects: (a) the
determination of formation oil contamination in SBFs, (b) toxicity
testing of SBFs and base fluids, (c) quantity of SBF discharged
(retention of base fluid on cuttings), and (d) seabed surveys at SBF-
cuttings discharge sites. Industry representatives formed work groups
to address these issues. The sections below describe their work.
1. Formation Oil Contamination Determination (Analytical)
The goal of this work group was to define the monitoring and
compliance method to determine crude oil (or other oil) contamination
of SBF-cuttings. The work group has issued several reports concerning
the static sheen test, and developed two replacement tests for
formation oil contamination, one based on fluorescence and the other on
gas chromatography with mass spectroscopy detection (GC/MS).
On September 28, 1998, the workgroup published the final draft of
the Phase I report entitled ``Evaluation of Static Sheen Test for
Water-based Muds, Synthetic-based Muds and Enhanced Mineral Oils. The
conclusions of the report are that the static sheen test is not a good
indicator of oil contamination in SBFs, and that in WBFs formation oil
contamination is often detected at 1.0 percent and sometimes as low as
0.5 percent.
On October 21, 1998, the work group published its final draft to
the Phase II report entitled ``Survey of Monitoring Approaches for the
Detection of Oil Contamination in Synthetic-based Drilling Muds.'' This
document lists thirteen methods that the work group considered as a
replacement to the static sheen test. From these thirteen, EPA selected
the reverse phase extraction method to be used on offshore drilling
sites, and the GC/MS method for onshore baseline measurements.
On November 16, 1998, the work group published its final draft of
the Phase III report entitled ``Laboratory Evaluation of Static Sheen
Replacements: RPE Method and GC/MS Method.'' This report provides the
methods. The future work of the Analytical Work Group is to validate
these methods.
2. Retention on Cuttings
The goals of this work group were to determine the SBF retention on
cuttings using the equipment currently used in the Gulf of Mexico
(GOM), and investigate ways of determining the total quantity of SBF
discharged when drilling a well. To address the first goal, API
reported data from GOM wells on the amount of SBF base fluid retained
on drill cuttings. The results were published on August 29, 1997, in a
report entitled ``Retention of Synthetic-Based Drilling Material on
Cuttings Discharged to the Gulf of Mexico.''
To address the second goal of determining the total quantity of SBF
discharged, the work group has created a spreadsheet which records
information allowing two independent analyses of the SBF quantity
discharged. One method is based on a mass balance of the SBF, and the
other is based on retort measurements of the cuttings wastestream. Both
methods of analyses carry certain benefits and drawbacks. By comparing
the results from the two analyses, EPA intends to select one method as
preferred for the final rule. The work group is currently gathering
these comparative data. The preferred method will then be validated for
inclusion in the final rule. At this time, EPA thinks that the retort
measurement is preferable to implement, and therefore it is the method
proposed today. As further information is gathered, however, EPA may
decide that attainment of the limit in the final rule is to be
determined by the mass balance method.
3. Toxicity Testing
The goal of this work group was to define the toxicity test for
monitoring and compliance of SBF-cuttings. EPA has indicated that the
test could be performed on either the stock base fluid, or the SBF
separated from the cuttings at the point of discharge.
Through data generated by members of the work group, the work group
has shown that SBF and synthetic base fluid toxicity are mainly evident
in the sedimentary phase. When measured in the suspended particulate
phase (SPP) in the current Mysid shrimp toxicity test, the toxicity is
not evident and the results are highly variable, and are easily
affected by the intensity of stirring and emulsifier content of the
SBF.
Having shown that an aqueous phase test is unlikely to yield
satisfactory results with SBFs and associated base fluids, the work
group has been investigating sediment toxicity tests, mainly the 10-day
sediment toxicity test with amphipods (ASTM E1367-92). To effect this
work, API funded a currently ongoing contract to evaluate four test
methods: 10-day acute sediment toxicity test with (a) Ampelisca abdita,
(b) Leptocheirus plumulosus, and (c) Mysidopsis bahia, and (d) microtox
tests. Main issues that the work group hopes to resolve are
discriminatory power of the method and variability in results. Since
the API contract work began, the work group has considered many
variables to the sediment toxicity test to ameliorate these problems.
The work group is investigating: organisms other than amphipods, such
as Mysid shrimp and polychaetes; shortening the length of the test,
i.e. from 10 days to 4 days; and the use of formulated sediments in
place of natural sediments. Work continues to determine the most
appropriate method to evaluate the toxic effect of the SBF discharged
with drill cuttings.
4. Environmental Effects/Seabed Surveys
The goal of this work group was to determine the spacial and
temporal recovery of the seafloor at sites where SBF-cuttings had been
discharged, and compare these effects with effects caused by the
discharge of WBF and WBF-cuttings discharge.
The work group performed a five-day screening cruise at three
offshore oil platforms where SBFs has been used and SBF-cuttings
discharged for the purpose of gathering preliminary environmental
effects information. This screening cruise, and its planning, was
performed in collaboration with EPA and with the use of the EPA Ocean
Survey Vessel Peter W. Anderson. The study conducted a preliminary
evaluation of offshore discharge locations and determine the areal
extent of observable physical, chemical, and biological impact. EPA
intended that this base information would provide (1) information
relative to the immediate concerns on impacts, and (2) valuable
preliminary information for designing future offshore assessments.
The study provided preliminary information on cuttings deposition,
SBF content of nearfield marine sediments,
[[Page 5498]]
anoxia in nearfield sediments, qualitative information on biological
communities in the area, and toxicity of field collected sediments. The
results of this survey were published on October 21, 1998, in a report
entitled ``Joint EPA/Industry Screening Survey to Assess the Deposition
of Drill Cuttings and Associated Synthetic Based Mud on the Seabed of
the Louisiana Continental Shelf, Gulf of Mexico.''
The ongoing effort of the work group is to address CWA 403(c)
permit requirements for seabed surveys by organizing collaborative
industry seabed surveys at selected SBF-discharge sites.
D. EPA Research on Toxicity, Biodegradation, Bioaccumulation
Subsequent to today's proposal, EPA plans to compare the relative
environmental effects of SBFs and OBFs in terms of (i) sediment and
aquatic toxicity, (ii) biodegradation, and (iii) bioaccumulation. The
methods development to occur as part of this research, and the
resulting data, are intended to be used towards the final stock base
fluid limitations and SBF discharge limitations proposed today.
The base fluids to consider in the sediment toxicity,
biodegradation, and bioaccumulation tests are the full range of
synthetic and oleaginous base fluids. These include the synthetic oils
such as vegetable esters, linear alpha olefins, internal olefins and
poly alpha olefins, the traditional base oils of mineral oil and diesel
oil, and the newer more refined and treated oils such as enhanced
mineral oil and paraffinic oils. These oily base fluids are common in
that they are immiscible (do not mix) with water, and form drilling
fluids that do not disperse in water.
The outline of this research plan in terms of goals and
considerations is as follows:
For sediment toxicity, this plan intends to investigate
the effects of base fluid, whole mud formulation, and crude oil
contamination on sediment toxicity as measured by the 10-day acute
sediment toxicity test performed in natural sediment with Ampelisca
abdita and Leptocheirus plumulosus. The goals of this research are
threefold:
Amend the EPA 10-day acute sediment toxicity test for
application to SBFs and base fluids.
Determine the LC50 values for the base fluids
by this method, potentially for determination of stock limitations
values.
Determine the effects of mud formulation and crude oil
contamination on sediment toxicity by maintaining the base fluid
constant. The purpose is to investigate the parameters which affect
toxicity in SBFs.
For aqueous phase toxicity, this plan intends to
investigate if any correlation exists between aqueous phase toxicity to
Mysid shrimp and sediment toxicity.
For biodegradation, this plan intends to perform the solid
phase test or modified solid phase test as developed by the Scottish
Office Agriculture, Environment and Fisheries Department for a range of
oily base fluids, and environments of the Gulf of Mexico, Offshore
California, Cook Inlet Alaska, and Offshore Alaska.
For bioaccumulation, this plan intends to test
bioconcentration in Macoma nasuta and Nereis virens.
The research concerning sediment toxicity testing that API supports
is seen as complementary to, and not overlapping with, this EPA plan.
API's goal is to identify a bioassay test organism and protocol to
accurately and reliably evaluate the toxicity of SBF and OBF in
sediments. The API research is concentrating efforts on using both
formulated and natural sediments, and possibly a test period shorter
than the standard 10-day EPA method. Thus, while EPA is focusing on
investigating the parameters that affect toxicity of SBFs, the API
research is looking ahead to discharge monitoring requirements with the
goal of identifying an appropriate and reliable test method.
E. EPA Investigation of Solids Control Technologies for Drilling Fluids
EPA has contacted numerous vendors of solids control equipment and
requested information on performance and cost of the various solids
separation units available. EPA has also received information from
operators data showing the performance of the vibrating centrifuge
technology. As part of its investigation of solids control equipment
used on offshore drilling platforms, EPA visited Amoco's Marlin
deepwater drilling project aboard the Amirante semi-submersible
drilling platform located in Viosca Knoll Block 915 approximately 100
miles south of Mobile, Alabama. The primary purpose of this site visit
was to observe the demonstration of the vibrating centrifuge drilling
fluid recovery device heretofore used only on North Sea drilling
projects. The device reportedly can produce drill cuttings containing
less than 6 percent by volume synthetic drilling fluid on wet cuttings
when well operated and maintained and used in conjunction with shale
shakers that are well operated and maintained. The information gathered
by the EPA during this trip is described in a report dated August 7,
1998, entitled ``Demonstration of the `Mud 10' Drilling Fluid Recovery
Device at the Amoco Marlin Deepwater Drill Site.''
F. Assistance From Other State and Federal Agencies
The United States Department of Interior Minerals Management
Service (MMS) maintains data of the number of wells drilled in offshore
waters under MMS jurisdiction, i.e., those that are not territorial
seas. In general, this covers the offshore waters beyond 3 miles from
the shoreline, which corresponds with the area were drilling wastes are
currently allowed for discharge and so is the same area affected by
this rule. MMS supplied data for years 1995, 1996, and 1997 of the
number of wells drilled in the GOM and offshore California according to
depth (less than or greater than 1000 feet water depth) and type of
well (exploratory or development). Since Texas jurisdiction over oil
and gas leases extends out to 10 miles, information was requested and
received from the Texas Railroad Commission regarding the number of
wells drilled in Texas territorial seas from 3 miles to 10 miles from
shore. This is the area in the GOM that is affected by this proposed
rule, but not included in the MMS data.
Information concerning the number of wells drilled in the state
waters of Upper Cook Inlet, Alaska, was gathered from the Alaska Oil
and Gas Commission. The Alaska Oil and Gas Commission provided
information of the number of wells drilled in Upper Cook Inlet for the
years 1995, 1996, and 1997, according to type of well as exploratory or
development.
MMS also assisted in developing the cruise plan of the screening
seabed survey mentioned in section V.C.4 above.
The United States Department of Energy (DOE) has been active in
assisting EPA to gather information concerning drilling waste disposal
methods and costs, and type of fuel used on offshore platforms. In
November 1998 Argonne National Laboratory, under contract with DOE,
published the results of this information gathering effort in a report
entitled ``Data Summary of Offshore Drilling Waste Disposal
Practices.''
Also under contract with DOE, Brookhaven National Laboratory
developed a comparative risk assessment for the discharge of SBFs. The
risk assessment, published November 1998, is entitled ``Framework for a
Comparative Environmental Assessment of Drilling Fluids.''
[[Page 5499]]
VI. Development 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 proportionate to the advancement of the drill bit. These
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 sent back down hole,
provided it still has characteristics to meet technical requirements.
Various sizes of drill cuttings are separated by the solids separations
equipment, and it is necessary to remove the fines (small sized
cuttings) as well as the large cuttings from the drilling fluid to
maintain the required flow properties.
SBFs, used or unused, are considered 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. Compared to
WBFs, SBFs are relatively easy to separate from the drill cuttings
because the drill cuttings do not disperse in the drilling fluid to the
same extent. 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 as
neat drilling fluid (drilling fluid not associated with cuttings).
The top of the well 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 (a) a water dispersible
drilling fluid such as a WBF, or (b) a water non-dispersible drilling
fluid such as an SBF. The decision to change the system from a WBF
water dispersible system to an OBF or SBF water non-dispersible system
depends on many factors including:
The operational considerations, i.e. rig type (risk of
riser disconnects with floating drilling rigs), rig equipment, distance
from support facilities,
The relative drilling performance of one type fluid
compared to another, e.g., rate of penetration, well angle, hole size/
casing program options, horizontal deviation,
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,
potential for gas hydrate formation,
Drilling fluid cost--base cost plus daily operating cost,
Drilling operation cost--rig cost plus logistic and
operation support,
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. This is due to the fact that these
operations are higher cost and can therefore better justify the higher
initial cost of SBF use.
The volume of cuttings generated while drilling the SBF intervals
of a well depends on the type of well, development or production, and
the water depth. According to analyses of the model wells provided by
industry representatives, wells drilled in less than 1,000 feet of
water are estimated to generate 565 barrels for a development well and
1,184 barrels for an exploratory well. Wells drilled in water greater
than 1,000 feet deep are estimated to generate 855 barrels for a
development well, and 1,901 for an exploratory well. These values
assume 7.5 percent washout, based on the rule of thumb reported by
industry representatives of 5 to 10 percent washout when drilling with
SBF. Washout is caving in or sluffing off of the well bore. Washout,
therefore, increases hole volume and increases the amount of cuttings
generated when drilling a well. Assuming no washout, the values above
become, respectively, 526, 1,101, 795, and 1,768, barrels.
The drill cuttings range in size from large particles on the order
of a centimeter in size to small particles a fraction of a millimeter
in size, called fines. As the drilling fluid returns from downhole
laden with drill cuttings, it normally is first passed through primary
shale shakers which remove the largest cuttings, ranging in size of
approximately 1 to 5 millimeters. The drilling fluid may then be passed
over secondary shale shakers to remove smaller drill cuttings. Finally,
a portion or all of the drilling fluid may be passed through a
centrifuge or other shale shaker with a very fine mesh screen, for the
purpose of removing the fines. It is important to remove fines from the
drilling fluid in order to maintain the desired flow properties of the
active drilling fluid system. Thus, the cuttings wastestream normally
consists of larger cuttings from the primary shale shakers and fines
from a fine mesh shaker or centrifuge, and may also consist of smaller
cuttings from a secondary shale shaker. Before being discharged, the
larger cuttings are sometimes sent through another separation device in
order to recover additional drilling fluid.
The recovery of SBF from the cuttings serves two purposes. The
first is to deliver drilling fluid for reintroduction to the active
drilling fluid system, and the second is to minimize the discharge of
SBF. The recovery of drilling fluid from the cuttings is a conflicting
concern, because as more aggressive methods are used to recover the
drilling fluid from the cuttings, the cuttings tend to break down and
become fines. The fines are not only more difficult to separate from
the drilling fluid, but as stated above they also deteriorate the
properties of the drilling fluid. Increased recovery from the cuttings
is more problematic for WBF than with 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.
These more aggressive methods may be justified for cuttings associated
with SBF so as to reduce the discharge of SBF. This, consequently, will
reduce the potential to cause anoxia (lack of oxygen) in the receiving
sediment as well as reduce the quantity of toxic organic and metallic
components of the drilling fluid discharged.
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. TSS makes up the bulk of the pollutant loadings, and 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
which are added to modify the viscosity. Because the quantity of TSS is
so high and consists of mainly large particles which settle quickly,
discharge of SBF drill cuttings can cause benthic
[[Page 5500]]
smothering and/or sediment grain size alteration resulting in potential
damage to invertebrate populations and alterations in benthic community
structure.
Additionally, environmental impacts can be caused by toxic,
conventional, and nonconventional pollutants adhering to the solids.
The adhered SBF drilling fluid is mainly composed, on a volumetric
basis, of the synthetic material, or more broadly speaking, oleaginous
material. The oleaginous material may also be toxic or bioaccumulate,
and it may contain priority pollutants such as polynuclear aromatic
hydrocarbons (PAHs). This oleaginous material may cause hypoxia
(reduction in oxygen) or anoxia in the immediate sediment, depending on
bottom currents, temperature, and rate of biodegradation. Oleaginous
materials which biodegrade quickly will deplete oxygen more rapidly
than more slowly degrading materials. EPA, however, thinks that fast
biodegradation is environmentally preferable to persistence despite the
increased risk of anoxia which accompanies fast biodegradation. This is
because recolonization of the area impacted by the discharge of SBF-
cuttings or OBF-cuttings has been correlated with the disappearance of
the base fluid in the sediment, and does not seem to be correlated with
anoxic effects that may result while the base fluid is disappearing. In
studies conducted in the North Sea, base fluids that biodegrade faster
have been found to disappear more quickly, and recolonization at these
sites has been more rapid.
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, 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.
B. Selection of Pollutant Parameters
1. Stock Limitations of Base Fluids
a. General.--EPA is proposing to establish BAT and NSPS that would
require the synthetic materials and other oleaginous materials which
form the base fluid of the SBFs and other non-aqueous drilling fluids
to meet limitations on PAH content, sediment toxicity and
biodegradation. The technology basis for meeting these limits would be
product substitution, or zero discharge based on land disposal or
injection if these limits are not met. These parameters are being
regulated to control the discharge of certain toxic and nonconventional
pollutants. A large range of synthetic, oleaginous, and water miscible
materials have been developed for use as base fluids. These stock
limitations on the base fluid are intended to encourage product
substitution reflecting best available technology wherein only those
synthetic materials and other base fluids which minimize potential
loadings and toxicity may be discharged.
b. PAH Content.--EPA proposes to regulate 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 on the order of
5 to 10 percent PAH in diesel oil and 0.35 percent PAH in mineral oil.
The PAHs typically found in diesel and mineral oil include the toxic
priority pollutants fluorene, naphthalene, phenanthrene, and others,
and nonconventional pollutants such as alkylated benzenes and
biphenyls. Thus, this stock limitation would be one component of a rule
reflecting the use of the best available technology.
c. Sediment Toxicity.--EPA proposes to regulate sediment toxicity
in base fluids and SBFs as a nonconventional pollutant parameter, as an
indicator for toxic components of base fluids or drilling fluid. Some
of the toxic components of the base fluids may include enhanced mineral
oils, internal olefins, linear alpha olefins, paraffinic oils,
vegetable esters of 2-hexanol and palm kernel oil, and other oleaginous
materials. Some of the possible toxic components of drilling fluids may
include the same components as the base fluid, and in addition mercury,
cadmium, arsenic, chromium, copper, lead, nickel, and zinc, formation
oil contaminants, and other intended or unintended components of the
drilling fluid. 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
synthetic base fluids have been shown to have lower toxicity than
diesel and mineral oil, but among the synthetic and other oleaginous
base fluids some are more toxic than others. Today's proposed discharge
option includes a sediment toxicity limitation of the SBF's base fluid
stock material, as measured by the 10-day sediment toxicity test (ASTM
E1367-92) using a natural sediment and Leptocheirus plumulosus as the
test organism.
Subsequent to this proposal and before the final rule, EPA intends
to gather information to determine how to most appropriately control
toxicity and solicit comment on these findings. The sediment toxicity
test may be altered, for instance, in terms of test organism (other
amphipods or possibly a polychaete), sediment type (formulated in place
of natural), or length of test (to shorten the 10-day test period).
Further, while today's proposal includes a sediment toxicity limitation
of the base fluid stock material, the final discharge option to control
toxicity might consist of a different option.
EPA would prefer to control sediment toxicity at the point of
discharge as opposed to controlling the base fluid. EPA realizes,
however, that the sediment toxicity test may be impractical to
implement as a discharge requirement due to potential problems in the
availability of uniform sediment and other factors affecting test
variability. If EPA finds, through subsequent research, that the
sediment toxicity test at the point of discharge is both practical and
superior to the base fluid toxicity as an indicator of the toxicity of
the SBF at the point of discharge, EPA might apply the sediment
toxicity test to the SBF at the point of discharge in place of today's
proposed method of the sediment toxicity test to the base fluid.
If the sediment toxicity test of neither the SBF at point of
discharge nor synthetic base fluid as a stock limitation is found to be
practical due to variability, lack of discriminatory power, or other
problems, EPA will search for an alternative toxicity test. One
candidate is modification to the current SPP toxicity test, or aquatic
phase toxicity test. EPA has several concerns with applying the current
SPP test to SBFs. EPA has received information from industry sources
and testing laboratories that the results from the SPP test applied to
SBFs are highly dependent on both the agitation when mixing the
seawater with the SBF and the amount and type of emulsifiers in the SBF
formulation. Further, results to date show that, compared to the
aquatic toxicity test, the sediment toxicity test provides a better
correlation with known toxicity effects of the various synthetic and
oleaginous base fluids, and the experimental situation more closely
mimics the actual fate of the drilling fluid. While EPA does not think
that the current SPP test is useful for application to SBFs,
modifications to either the method or limitation may render it
functional. Thus, EPA intends to investigate the aquatic phase toxicity
test as a possible control in the event that the sediment toxicity test
of the drilling fluid is impractical and the
[[Page 5501]]
sediment toxicity test of the base fluid is either impractical or
inadequate to control the toxicity of the SBF at the point of
discharge.
EPA intends, therefore, to investigate further the most appropriate
test method for controlling toxicity of SBF discharges, and to validate
this method. EPA intends to publish any additional data concerning this
limitation in a notice prior to publication of the final rule.
d. Biodegradation.--EPA proposes to limit biodegradation as an
indicator of the extent, in level and duration, of the toxic effect of
toxic components of nonconventional pollutants present in the base
fluids, e.g., poly alpha olefins, enhanced mineral oils, internal
olefins, linear alpha olefins, paraffinic oils, and vegetable ester of
2-hexanol and palm kernel oil. The various SBF base fluids vary widely
in biodegradation rate, as measured by the solid phase test and
simulated seabed tests. Based on results from seabed surveys at sites
where various base fluids have been discharged with drill cuttings, EPA
believes that the results from both measurement methods are indicative
of the relative rates of biodegradation in the marine environment. In
addition, EPA thinks this parameter correlates strongly with the rate
of recovery of the seabed where SBF-cuttings have been discharged.
While EPA is proposing to use the solid phase test to measure
compliance with the biodegradation limitation, this test is not yet an
EPA validated method. In addition to validating the method for the
final rule, EPA intends to gather additional data in support of the
biodegradation rate limitation. EPA plans to present any additional
data it collects towards this limitation in a notice subsequent to
today's proposed rule and before the final rule.
e. Bioaccumulation.--While not a part of today's proposal, EPA is
also considering establishing BAT and NSPS that would require the
synthetic materials and other base fluids used in non-aqueous drilling
fluids to meet limitations on bioaccumulation potential. The regulated
parameters would be the nonconventional and toxic priority pollutants
that bioaccumulate. Based on current information, EPA believes that the
base fluid controls on PAH content, sediment toxicity, and
biodegradation rate being proposed today are sufficient to control
bioaccumulation. EPA intends, however, to study the bioaccumulation
potential of the various synthetic base fluids for comparison, and
subsequently solicit comments on the results if EPA thinks that some
measure of bioaccumulation potential is needed to control adequately
the SBF-cuttings wastestream.
2. Discharge Limitations
a. Free Oil.--Under BPT and BCT limitations for SBF-cuttings, EPA
would retain the prohibition on the discharge of free oil as determined
by the static sheen test. Under this prohibition, drill cuttings may
not be discharged when the associated drilling fluid would fail the
static sheen test defined in Appendix 1 to 40 CFR Part 435, Subpart A.
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 pollutants oil and grease which separate from the SBF and
cause 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 (such as 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 synthetic material comprising the SBF may
rise to the surface to cause a sheen. These 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 proposal 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, however, is not
intended to control formation oil contamination nor the total quantity
of conventional pollutants discharged.
b. Formation Oil Contamination.--Formation oil contamination of the
SBF associated with the cuttings would be limited under BAT and NSPS.
Formation oil is an ``indicator'' pollutant for the many toxic and
priority pollutant components present in formation (crude) oil, such as
aromatic and polynuclear aromatic hydrocarbons. These pollutants
include benzene, toluene, ethylbenzene, naphthalene, phenanthrene, and
phenol. (See Development Document Chapter VII). The primary limitation
is based on a fluorescence test. This test is considered an
appropriately ``weighted'' test because crude oils containing more
toxic aromatic and PAH components tend to show brighter fluorescence
and hence noncompliance at a lower level of contamination. Since
fluorescence is a relative brightness test, gas chromatography with
mass spectroscopy detection (GC/MS) is provided as a baseline method
before the drilling fluid is delivered for use, and is also available
as an assurance method when the results from the fluorescence
compliance method are in doubt.
c. Retention of SBF on Cuttings.--The retention of SBF on drill
cuttings would be limited under BAT and NSPS. This limitation controls
the quantity of SBF discharged with the drill cuttings. Both
nonconventional and priority toxic pollutants would be controlled by
this limitation. Nonconventionals include the SBF base fluids, such as
vegetable esters, internal olefins, linear alpha olefins, paraffinic
oils, mineral oils, and others. This limitation would also limit the
toxic effect of the drilling fluid and the persistence or
biodegradation of the base fluid. Several toxic and priority pollutant
metals are present in the barite weighting agent, including arsenic,
chromium, copper, lead, mercury, nickel, and zinc, and nonconventional
pollutants such as aluminum and tin.
The emulsifying and wetting agents of the SBF would also be
controlled by limiting the amount of SBF discharged. EPA solicits
information concerning the composition of the wetting and emulsifying
agents so that they can be classified as conventional, nonconventional,
or toxic pollutants.
Today's proposed rule uses the retort method to determine
compliance with the limit. The limit is expressed as percentage base
fluid on wet cuttings (weight/weight), averaged over the well sections
drilled with SBF. This method has not yet been validated by EPA.
Further, EPA is currently researching a mass balance method as an
alternative method to determine the quantity of SBF discharged. After
EPA has gathered sufficient data using the two methods in a comparative
analysis, EPA intends to validate the preferred method and solicit
comment concerning the method to be applied for the final rule.
3. Maintenance of Current Requirements
EPA would retain the existing BAT and NSPS limitations on the stock
barite of 1 mg/kg mercury and 3 mg/kg
[[Page 5502]]
cadmium. These limitations would control the levels of toxic pollutant
metals because cleaner barite that meets the mercury and cadmium limits
is also likely to have reduced concentrations of other metals.
Evaluation of the relationship between cadmium and mercury and the
trace metals in barite shows a correlation between the concentration of
mercury with the concentration of arsenic, chromium, copper, lead,
molybdenum, sodium, tin, titanium and zinc. (See the Offshore
Development Document in Section VI).
EPA also would retain the 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 percent by volume PAHs, which constitute the more
toxic components of petroleum products.
C. Regulatory Options Considered for SBFs Not Associated With Drill
Cuttings
Today EPA proposes, under BPT, BCT, BAT, and NSPS, zero discharge
for SBFs not associated with drill cuttings. This option is technically
available and economically achievable with equipment commonly used. It
is also current industry practice due to the value of SBFs recovered
and reused. Since this option reflects current industry practice, it
has no non-water quality environmental impacts.
Industry sources have indicated that at times, there may be minor
drips or spills of SBFs that occur on the platform. EPA is considering
whether these discharges should be governed by the zero discharge
requirement, or whether to view the zero discharge requirements as
being limited to discharge of whole drilling fluids, and allowing
unintentional drips and spills to be treated as miscellaneous wastes.
EPA solicits comment on this approach. EPA thinks that the best way to
control these discharges would be through the use of BMPs and solicits
comment on what types of BMPs would be effective for controlling these
discharges and whether such BMPs should be part of this effluent
guideline or be applied by the permit authority.
D. Regulatory Options Considered for SBFs Associated With Drill
Cuttings
EPA considered two options for today's proposed rule for SBFs
associated with drill cuttings, or SBF-cuttings: a discharge option and
a zero discharge option. EPA has selected the discharge option as the
basis for today's proposal. As detailed above, this discharge option
controls under BAT and NSPS the stock base fluid through limitations on
PAH content, sediment toxicity, and biodegradation rate, and controls
at the point of discharge under BPT and BCT sheen formation and under
BAT and NSPS formation oil content and quantity of SBF discharged. The
discharge option maintains current requirements of stock limitations on
barite of mercury and cadmium, and the diesel oil discharge
prohibition. EPA at this time thinks that all of these components are
essential for appropriate control of the SBF cuttings wastestream.
Although not the basis for today's proposal, EPA considered zero
discharge as an option for BPT, BCT, BAT, and NSPS. Under zero
discharge all pollutants would be controlled in SBF discharges. This
option was clearly technically feasible and economically achievable
because in the past SBFs did not exist, and industry was able to
operate using only the traditional non-dischargeable OBFs based on
diesel oil and mineral oil.
EPA presently rejects zero discharge as the preferred option
because it would result in unacceptable non-water quality environmental
impacts. If EPA were to choose zero discharge for SBF-cuttings,
operators would not have an incentive to use SBFs since they are more
expensive than OBFs. Thus, if EPA requires zero discharge, OBF-cuttings
would continue to be injected or shipped to shore for land disposal.
EPA's analysis shows that under this option as compared to the
discharge option, for existing and new sources combined, there would be
172 million pounds annually of OBF-cuttings shipped to shore for
disposal in non-hazardous oilfield waste sites and 40 million pounds
annually injected, with associated fuel use of 29,000 BOE and annual
air emissions of 450 tons. EPA believes these impacts far outweigh the
water impacts associated with these discharges detailed in Section VIII
of this preamble. EPA's current analysis shows that the impacts of
these discharges to water are of limited scope and duration,
particularly if EPA controls the discharges of SBFs to the best
environmental performers that also meet the technical requirements
needed to drill. By contrast, the landfilling of OBF-cuttings is of a
longer term duration and associated pollutants may effect ambient air,
soil, and groundwater quality. For these reasons, under EPA's authority
to consider the non-water quality environmental impacts of its rule,
EPA rejects zero discharge of SBF-cuttings.
Nonetheless, while discharge with adequate controls is preferred
over zero discharge, discharge with inadequate controls is not
preferred over zero discharge. EPA believes that to allow discharge of
SBF-cuttings, 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 determination of PAH content, sediment toxicity,
biodegradation, bioaccumulation, the quantity of SBF discharged, and
formation oil contamination. The successful completion of these efforts
is necessary for EPA to continue to reject zero discharge.
E. BPT Technology Options Considered and Selected
As previously discussed, 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. See 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
[[Page 5503]]
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. Therefore, EPA has not considered these factors in
developing the limitations being proposed today. See Weyerhaeuser
Company v. Costle, 590 F. 2d 1011 (D.C. Cir. 1978).
EPA today proposes BPT effluent limitations for the cuttings
contaminated with SBF and other non-aqueous drilling fluids. The BPT
effluent limitations proposed today would control free oil as a
conventional pollutant. The limitation is no free oil as measured by
the static sheen test, performed on SBF separated from the cuttings.
In setting the no free oil limitation, EPA considered the sheen
characteristics of currently available SBFs. Since this requirement is
currently met by dischargers in the Gulf of Mexico, EPA anticipates no
additional costs to the industry to comply with this limitation.
EPA also considered a BPT level of control for the quantity of SBF
discharged with the cuttings consisting of improved use of currently
existing shale shaker equipment. However, EPA did not have enough
information to establish BPT beyond current performance. Further, EPA
is not setting a BPT limit based on current performance because
operators already have incentive to recover as much SBFs as possible
through the optimization of existing equipment due to the value of the
SBFs. Therefore, a BPT limitation based on the current equipment, and
as it is currently used, would not have any practical effect on the
quantity of SBF discharged with the cuttings. Further, given that the
BAT and NSPS limitations would be more stringent and control the
conventional pollutants in addition to the non-conventional and toxic
pollutants, EPA saw no reason to expend time and resources to develop a
different, less restrictive BPT limit.
F. BCT Technology Options Considered and Selected
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
percent).
In today's proposal, EPA is proposing to establish a BCT limitation
of no free oil equivalent to the BPT limitation of no free oil as
determined by the static sheen test. In developing BCT limits, EPA
considered whether there are technologies (including drilling fluid
formulations) that achieve greater removals of conventional pollutants
than proposed 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 than proposed for BPT that are also cost-reasonable under
the BCT Cost Test, and accordingly EPA proposes BCT effluent
limitations equal to the proposed BPT effluent limitations guidelines.
G. BAT Technology Options Considered and Selected
EPA today proposes BAT effluent limitations for the cuttings
contaminated with SBFs. The BAT effluent limitations proposed today
would control the stock base fluids in terms of PAH content, sediment
toxicity, and biodegradation. Controls at the point of discharge
include formation oil contamination and the quantity of SBF discharged.
This level of control has been developed taking into consideration the
availability and cost of oleaginous (SBF) base fluids in terms of PAH
content, sediment toxicity, and biodegradation rate; the frequency of
formation oil contamination at the control level; the performance and
cost of equipment to recover SBF from the drill cuttings. The technical
availability and economic achievability of today's proposed limitations
is discussed below by regulated parameter.
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 few primary base fluids. These
include the vegetable esters, internal olefins, linear alpha olefins,
and poly alpha olefins. Thus, these are the base fluids for which EPA
has data and costs to develop the effluent limitations of today's
proposed rule. In this document, vegetable ester means a monoester of
2-ethylhexanol and saturated fatty acids with chain lengths in the
range C8-C16, internal olefin means a series of
isomeric forms of C16 and C18 alkenes, linear
alpha olefin means a series of isomeric forms of C14 and
C16 monoenes, and poly alpha olefins means a mix mainly
comprised of a hydrogenated decene dimer C20H62
(95%), with lesser amounts of C30H62 (4.8%) and
C10H22 (0.2%). EPA also has data on other
oleaginous base fluids, such as enhanced mineral oil, paraffinic oils,
and the traditional OBF base fluids mineral oil and diesel oil.
The stock base fluid limitations presented below are based on
currently available base fluids, and the limitations would be
achievable through product substitution. EPA anticipates that the
currently available and economically achievable base fluids meeting all
requirements would include vegetable esters and internal olefins. EPA
also solicits data on linear alpha olefins and certain paraffinic oils
to determine whether these base fluids are comparable in terms of
sediment toxicity, biodegradation, and bioaccumulation.
b. PAH Content Technical Availability.--Today's proposed limitation
of PAH content is 0.001 percent, or 10 parts per million (ppm), weight
percent PAH expressed as phenanthrene. 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. EPA's proposed 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 linear
alpha olefins, internal olefins, vegetable esters, certain enhanced
mineral oils, synthetic paraffins, certain non-synthetic paraffins, and
others. See the Development Document, Chapter VII. Compliance with the
BAT and NSPS stock limitations on PAH content may be achieved by
product substitution.
c. Sediment Toxicity Technical Availability.--EPA is today
proposing a sediment toxicity stock base fluid limitation that would
allow only the discharge of SBF-cuttings using base fluids as toxic or
less toxic, but not more toxic, than C16-C18
internal olefin.
[[Page 5504]]
Alternatively, this limitation could be expressed as the
LC50 of the base fluid minus the LC50 of the
C16-C18 internal olefin shall not be less than
zero. Based on information available to EPA at this time, the only base
fluids which would attain this limitation are the internal olefins and
vegetable esters.
EPA finds this limit to be technically available because
information in the rulemaking record supports that internal olefin SBFs
and vegetable ester SBFs together have performance characteristics
enabling them to be used in a wide variety of drilling situations
offshore. Marketing data given to the EPA shows that, at least for
certain of the major drilling fluid suppliers, internal olefin SBFs are
currently the most popular SBFs used in the Gulf of Mexico.
Various researchers have performed toxicity testing of the
synthetic base fluids with the 10-day sediment toxicity test (EPA/600/
R-94/025) using a natural sediment and Leptocheirus plumulosus as the
test organism. The synthetic base fluids have been shown to have lower
toxicity than diesel and mineral oil, and among the synthetic and other
oleaginous base fluids some are more toxic than others. For example,
Still et al. reported the following 10-day LC50 results,
expressed as mg base fluid/Kg dry sediment: diesel LC50 of
850, enhanced mineral oil LC50 of 251, internal olefin
LC50 of 2,944, and poly alpha olefin LC50 of
9,636. A higher LC50 value means the material is less toxic.
Similar results, with the same trend in toxicity in the base fluids
above, have been reported by Hood et al. Candler et al. performed the
10-day sediment toxicity test with the amphipod Ampelicsa abdita in
place of Leptocheirus plumulosus, and again obtained very similar
results as follows: diesel LC50 of 879, enhanced mineral oil
LC50 of 557, internal olefin LC50 of 3,121, and
PAO LC50 of 10,680.
None of these researchers reported sediment toxicity values for
vegetable esters. Recently, industry has evaluated a number of base
fluids including vegetable esters. While the absolute values are not
comparable because the tests were performed on the drilling fluid and
not just the base fluid, the results showed the vegetable ester to be
less toxic than the internal olefin.
Researchers in the United Kingdom and Norway investigating effects
in the North Sea have conducted sediment toxicity tests on other
organisms, namely Corophium volutator and Abra alba. Similar trends
were seen in the measured toxicity, with vegetable ester having very
low sediment toxicity (very high LC50), poly alpha olefin
having a mid range toxicity, and internal olefin having a higher
toxicity, in this comparison.
While the poly alpha olefins were found to have the lowest toxicity
of the measured base fluids (excludes vegetable esters), EPA did not
base the toxicity limitation on poly alpha olefins because, as
presented below, they biodegrade much more slowly and so are unlikely
to pass the biodegradation limitation. EPA intends to generate and
gather additional data comparing the toxicity of the various base
fluids, especially to compare the vegetable ester toxicity with that of
the olefins since, at this time, directly comparable data is not
available. If vegetable esters are found to have significant reduced
toxicity compared to the other base fluids, EPA may choose to base the
toxicity limitation on vegetable esters. EPA has concerns, however,
over the technical performance and possible non-water quality
implications with the use of vegetable ester as the only technology
available to meet the stock base fluid limitations, as discussed below
under biodegradation.
As an alternative, EPA solicits comment on a numeric limitation of
a minimum LC50 of 2,600 mg base fluid/Kg dry sediment as an
appropriate level of control, based on the toxicity of
C16-C18 internal olefins as determined by the 10-
day sediment toxicity test using Leptocheirus plumulosus as the test
organism. If EPA pursues this approach, EPA expects that it may need to
revise this numeric limitations due to the variability currently
experienced with this test.
d. Biodegradation Rate Technical Availability.--Today's proposed
limitation of biodegradation rate for the base fluid, as determined by
the solid phase test, is equal to or faster than the rate of a
C16-C18 internal olefin. Alternatively, this
limitation could be expressed as the percent of the base fluid degraded
at 120 days minus the percent of C16-C18 internal
olefin degraded at 120 days shall not be less than zero. With this
limitation the base fluids currently available for use include
vegetable ester, linear alpha olefin, internal olefins, and possibly
certain linear paraffins. Combined with the other stock base fluid
limitations of PAH content and sediment toxicity, the base fluids for
which EPA has data that would attain all three limitations are internal
olefins and vegetable esters.
EPA finds this limit to be technically available because
information in the rulemaking record supports that internal olefin SBFs
and vegetable ester SBFs together have performance characteristics to
address the broad variety of drilling situations found offshore.
As an alternative to today's proposal, EPA solicits comment on a
numeric limitation of a minimum biodegradation rate of 68 percent base
fluid dissipation at 120 days for the standardized solid phase test. If
EPA pursues this approach, EPA expects that it may need to revise this
numeric limitations as additional test results are generated.
As with the sediment toxicity test presented above, due to the lack
of data from the biodegradation test EPA again intends to propose a
limitation based on comparative testing rather than propose a numerical
limitation. Therefore, if SBFs based on fluids other than internal
olefins and vegetable esters are to be discharged with drill cuttings,
data showing the biodegradation of the base fluid should be presented
with data, generated in the same series of tests, showing the
biodegradation of the internal olefin as a standard. EPA prefers this
approach rather than set a numerical limitation at this time because of
the small amount of data available to EPA upon which to base a
numerical limitation. EPA sees this as an interim solution to the
problem of having insufficient information at the time of this proposal
to provide a numerical limitation, in that it still provides a
limitation based on the performance of available technologies.
Rates of biodegradation for synthetic and mineral oil base fluids
have been determined by both the solid phase and the simulated seabed
test, and the relative rates of biodegradation among these two tests
agree. These tests have found that, the order of degradation, from
fastest to slowest, is as follows: vegetable ester > linear alpha
olefin > internal olefin > linear paraffin > mineral oil > poly alpha
olefin.
EPA has selected the internal olefin as the basis for the
biodegradation rate limitation instead of the vegetable ester for two
reasons: technical performance and non-water quality environmental
impacts. Industry representatives have reported that SBFs using esters
currently on the market today are not adequate choices for most
deepwater drilling applications. Reportedly, the available esters
thicken considerably at the cold temperatures encountered in the riser
in deep water. This thickening can cause excessive pressure surges when
attempting to re-initiate circulation. These pressure surges can result
in breakdown of exposed formations resulting in severe SBF losses to
the destabilized formations. In addition to SBF losses, pressure surges
can destabilize the formation to the extent of hole collapse and loss
of any
[[Page 5505]]
drilling tools downhole. EPA solicits comment concerning the maximum
depth at which vegetable ester SBFs are practical, the development on
new esters with lower viscosity, and if special systems, such as subsea
pumping systems, ameliorate the pumping difficulties.
Cost is a factor in encouraging the use of SBFs in place of OBFs.
Industry representatives have told EPA that vegetable ester SBF costs
about twice as much as internal olefin SBF. EPA believes that if the
lower cost internal olefin SBFs can be discharged, then more wells
currently drilled with OBF would be encouraged to convert to SBF than
if only the more expensive vegetable ester SBFs were available for
discharge. This conversion is preferable for the improvements in non-
water quality environmental impacts (see section VII below). If future
research shows that vegetable esters have a significantly reduced
toxicity in addition to the proven faster rate of biodegradation, EPA
may consider more stringent stock base fluid limitations to favor the
use of vegetable ester SBFs for the final rule.
e. Economic Achievability of Stock Base Fluid Controls.--EPA finds
that the proposed stock base fluid controls are economically
achievable. Industry representatives have told EPA that while the
synthetic base fluids are more expensive than diesel and mineral oil
base fluids, the savings in discharging the SBF-cuttings versus land
disposal or reinjection of OBF-cuttings more than offsets the increased
cost of SBFs. Thus, it reportedly costs less for operators to invest in
the more expensive SBF provided it can be discharged. The stock base
fluid limitations proposed above allow use of the currently popular
SBFs based on internal olefins ($195/bbl) and vegetable esters ($380/
bbl). For comparison, diesel oil-based drilling fluid costs about $65/
bbl, and mineral oil-based drilling fluid costs about $75/bbl.
According to industry sources, currently in the Gulf of Mexico the most
widely used and discharged SBFs are, in order of use, based on internal
olefins, linear alpha olefins, and vegetable esters. Since the stock
limitations allow the continued use of the preferred internal olefin
and vegetable ester SBFs, EPA attributes no additional cost due to the
stock base fluid requirements other than monitoring (testing and
certification) costs. EPA expects that these monitoring costs will fall
upon the base fluid suppliers as a marketing cost. As further described
in Section XII, EPA anticipates that PAH monitoring would occur
batchwise, and sediment toxicity and biodegradation monitoring would
occur once annually per synthetic base fluid per supplier.
Pursuant to EPA's further research into sediment toxicity and
biodegradation, EPA may propose limits for the final rule that are
different than the limits proposed today. If the limits were to allow
only more expensive SBFs, such as the vegetable ester, EPA would likely
estimate a cost to comply with the stock base fluid limits for those
operators who currently use and discharge the less expensive SBFs, for
instance those based on internal olefins.
2. Discharge Limitations Technical Availability and Economic
Achievability
a. Formation Oil Contamination of SBF-Cuttings.--Today's proposed
formation oil contamination limitation of the SBF adhered to the drill
cuttings is ``weighted'' to detect contamination by highly aromatic
formation oils at lower concentrations than formation oils with lower
aromatic contents. Under the proposed limitation approximately 5
percent of all (all meaning a large representative sampling) formation
oils would fail (not comply) at 0.1 percent contamination and 95
percent of all formation oils will fail at 1.0 percent contamination.
The majority of formation oils would cause failure when present in SBFs
at a concentration of about 0.5 percent (vol/vol).
EPA is proposing two methods for the determination of formation oil
in SBFs. Analysis by gas chromatography with mass spectroscopy
detection (GC/MS) would apply to any SBF being shipped offshore for
drilling to allow discharge of the associated cuttings. During
drilling, the SBF would be required to comply with the limitation of
formation oil contamination as determined by the reverse phase
extraction (RPE) method. SBFs found to be non-compliant by the RPE
method could, at the operators discretion, be confirmed by testing with
the GC/MS method. Results from the GC/MS method would supersede those
of the RPE method.
EPA intends that the limitation proposed on formation (crude) oil
contamination in SBF is no less stringent that the limitation imposed
on WBF through the static sheen test. A study concerning this issue
found that in WBF, the static sheen test detected formation oil
contamination in WBF down to 1 percent in most cases, and down to 0.5
percent in some cases.
Currently, only a very small percent of WBF cannot be discharged
due to presence of formation oil as determined by the static sheen
test. EPA solicits information regarding the frequency of formation oil
contamination at this level of control. EPA has received some anecdotal
information to the effect that far less than one percent of SBF
cuttings would not be discharged due to formation oil contamination at
this level of control. Based on the available information, EPA believes
that only a very minimal amount of SBF will be non-compliant with this
limitation and therefore be required to dispose of SBF-cutting onshore
or by injection. EPA thus finds that this limitation is technically
available. EPA also finds this option to be economically achievable
because there is no reason why formation oil contamination would occur
more frequently under this rule than under the current rules which
industry can economically afford. For calculation purposes, EPA has
determined that no costs are associated with this requirement other
than monitoring and reporting costs, which are minimal costs for this
test for this industry.
b. Retention of SBF on Cuttings.--This limitation considers the
technical availability of methods to recover SBF from the cuttings
wastestream. EPA evaluated the performance of several technologies to
recover SBF from the cuttings wastestream and their costs, as detailed
in the Development Document. EPA also considered fuel use, safety, and
other considerations.
The solids control system typically consists of, at a minimum, a
primary shale shaker to remove the larger cuttings. Typically, all or a
portion of the drilling fluid is then passed through a secondary shale
shaker or ``mud cleaner'' to remove the small particle cuttings, or
``fines,'' before being recirculated to the active mud system. Greater
efficiencies in the use of these currently used technologies through
reduced loadings and more even flow across the screens, better
maintenance of the screens, and better integration of the solids
control system would help operators achieve these proposed discharge
limitations. An ancillary or alternative method to reduce SBF
discharges is to retain the fines for on shore disposal. Because of
their small size and large surface area, the fines retain more drilling
fluid than an equal amount of larger cuttings coming off the shale
shakers. Therefore, while the bulk of the cuttings may be discharged,
retaining the fines for on shore disposal can be used to
disproportionately reduce the overall discharges of SBF.
The American Petroleum Institute (API) performed a study in 1997
which gathered data on SBF retention on drill cuttings. Data gathered
in the study show the long term average retention
[[Page 5506]]
rate of SBF on cuttings, weighted by hole volume, is 10.6 percent from
the primary shale shaker and 15.0 percent from the secondary shale
shaker, expressed as weight synthetic base fluid per weight of wet
cuttings. Industry representatives further estimated that the cuttings
from the primary shale shaker comprise 80 percent of the total cuttings
wastestream, and the remaining 20 percent is removed by either the
secondary shale shaker or other devices to remove very small cuttings,
or fines. EPA used this information to calculate a long term average
weighted retention of 11.5 percent base fluid on wet cuttings using the
current technologies employed in the Gulf of Mexico.
Recently, in the wake of the development of SBFs and discharge
limitations in the North Sea, new cuttings cleaning devices have been
developed which reduce SBF retained on the cuttings. An effective
device consists of a conically shaped vibrating centrifuge, which
removes recycle-grade SBF from the cuttings coming off the primary
shale shakers. EPA selected this conical vibrating centrifuge as the
model technology on which to base its performance and cost
calculations. The manufacturer of the device has supplied EPA with
detailed performance data and some cost information of this device. The
performance has been confirmed by one operator, showing retention data
for twelve wells and comparing the vibrating centrifuge with shale
shaker technology. In addition, EPA was invited by an operator in the
Gulf of Mexico to observe the operation of the vibrating centrifuge.
EPA has learned that the operator has written a report concerning the
operation of this SBF recovery device, but this report has not been
made available to EPA. The operator has informed EPA as to the cost of
implementing the vibrating centrifuge, and EPA used this cost
information in determining the total cost of implementation. EPA is
aware of at least one other company that makes a similar centrifugal
device to recover SBFs from drill cuttings, although EPA has not
received performance or costs for this machine.
The limitation proposed today for retention of SBF is 10.2 percent
base fluid on wet cuttings (weight/weight), averaged by hole volume
over the well sections drilled with SBF. Those portions of the cuttings
wastestream that are retained for no discharge are factored into the
weighted average with a retention value of zero. The limit assumes that
SBF-cuttings processed by the vibrating centrifuge technology comprise
80 percent of the wastestream while the remaining 20 percent is
comprised of SBF-cuttings from the secondary shale shaker. Thus, from
the available data EPA determined that the retention attained for 95
percent of volume-weighted well averages was 7.22 for the vibrating
centrifuge and 22.0 for the secondary shale shakers. Applying the
assumption of an 80/20 split between the two wastestreams, EPA
determined the weighted average retention regulatory limit of 10.2
percent.
Based on current performance of the vibrating centrifuge
technology, 95 percent of all volume-weighted average values for
retention of drilling fluids over the course of drilling a well are
expected to be less than the proposed limit. Some, but not all, of the
variability between wells is due to factors under the control of the
operators. EPA believes that the proposed limit can be met at all times
by providing better attention to the operation of the technology and by
keeping track of the weighted average for retention as the well is
being drilled. If the trend in weighted average retention appears to
the operator as if the average retention for a particular well will
exceed the limitation prior to completion of the well then EPA
recommends that the operator retain some or all of the remaining
cuttings for no discharge. This is feasible because retention of SBF on
drill cuttings is generally low in the early stages of drilling a well
and it increases as the well goes deeper.
EPA used the same statistical analysis to determine the long term
average retention values. These values were used for cost and loadings
calculations. For the vibrating centrifuge and the secondary shale
shaker, respectively, EPA determined that the long term between-well
average percent retention of SBF on cuttings was 5.14 and 15.00.
Applying the assumption of an 80/20 split between the two wastestreams,
the long term average value for cost and loading calculations is 7.11
percent SBF retained on wet cuttings. Cost and loadings calculations
also assumed 7.5 percent washout of the well bore.
EPA finds that a well-average limit of 10.2 percent base fluid on
wet cuttings is 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 $5.0 MM. This savings results because the value of the SBF recovered
is greater than the cost of implementation of the technology. This
analysis is presented in Section IX of today's notice, and in greater
detail in the Development Document.
EPA thinks that this regulatory limitation is necessary to both
hasten and broaden the use of improved SBF recovery devices, even
though industry may be inclined to implement the SBF recovery
technology to save valuable SBF irrespective of the limitation. There
could be several reasons why industry does not already use the model
SBF recovery technology even though, in EPA's assessment, it saves the
operator money. For one, market acceptance and market penetration of
the vibrating centrifuge could be a reason. The vibrating centrifuge
recovery technology is a new technology that was developed in the North
Sea and has only been demonstrated a few times in the United States.
Secondly, the cost and resources devoted to retrofitting might only
benefit a small portion of the wells drilled by an operator. This is
because only a small fraction of wells, about 13 percent in EPA's
analysis, are drilled with SBFs. To counter this, however, is the fact
that most SBF wells are concentrated in the deep water. EPA projects
that 75 percent of all wells drilled in the deepwater would use SBFs.
In addition, retrofitting costs and market forces would encourage the
dedication of drill platforms equipped with improved SBF recovery
technology to the drilling of SBF wells. The use of improved SBF
recovery devices in the North Sea is a case in point. Operators have
reported to EPA that in the North Sea they were reluctant to use
improved SBF recovery devices, and eventually did so only in response
to more stringent regulatory requirements. These operators report that
their total cost to drill an SBF well actually went down as they
implemented the improved SBF recovery devices because of the value of
the SBF recovered.
H. NSPS Technology Options Considered and Selected
The general approach followed by EPA for developing NSPS options
was to evaluate the best demonstrated SBFs and processes for control of
priority toxic, nonconventional, 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
[[Page 5507]]
level of control for new sources. See section X, Economic Analysis.
Therefore, EPA is proposing that NSPS be established equivalent to BPT
and BAT for conventional, priority, and nonconventional pollutants.
VII. Non-Water Quality Environmental Impacts of Proposed
Regulations
A. Introduction and Summary
The elimination or reduction of one form of pollution has the
potential to aggravate other environmental problems. Under sections
304(b) and 306 of the CWA, EPA is required to consider these non-water
quality environmental impacts (including energy requirements) in
developing effluent limitations guidelines and NSPS. In compliance with
these provisions, EPA has evaluated the effect of this proposed
regulation on air pollution, energy consumption, solid waste generation
and management, consumptive water use, safety, and vessel traffic.
Based on this evaluation, EPA currently prefers the discharge
option over the zero discharge option because of the non-water quality
environmental impacts that would occur with zero discharge, compared to
the water quality impacts that would occur with discharge as controlled
by this proposed rule. Thus, non-water quality environmental impacts
are a major consideration for this rule because of the nature of the
wastes and where the wastes are generated and disposed.
If SBF-cuttings cannot be discharged, cuttings from SBF wells would
have to be transported to shore for treatment and disposal, or made
into a slurry and injected on-site. In this case, EPA assumes that most
operators will not use SBF in place of OBF, because SBFs cost more than
OBFs. On the other hand, if SBF-cuttings can be discharged, not only
are non-water quality environmental impacts from current SBF wells
drastically reduced, but EPA also estimates that some OBF wells would
convert to SBF, further decreasing these impacts. EPA estimates that in
the Gulf of Mexico (GOM) 20 percent of OBF wells will convert to SBF
wells. EPA also estimates that these GOM OBF wells are in shallow water
(less than 1000 feet). In deep water, EPA assumes that those wanting to
use SBFs are already doing so and therefore these facilities are not
considered to yield non-water quality environmental impacts reductions.
In offshore California and Cook Inlet, Alaska, EPA assumes that all OBF
wells will convert, because of the greater expense of OBF-cuttings
discharge and an ever greater concern for non-water quality
environmental impacts in these areas as compared to the GOM. For
example, disposal of OBF-cuttings in Cook Inlet, Alaska, would likely
require the barging of the waste to the lower 48 States. Air quality in
California is a continuing concern and therefore there is pressure to
keep air emissions from oil and gas drilling activities in the
neighboring offshore waters at a minimum.
In total, for existing and new sources under the discharge option,
EPA estimates that air emissions would be reduced by 72 tons per year,
based on OBF facilities switching to SBF. If the zero discharge option
was selected, however, air emissions would increase by 378 tons per
year, based on SBF to OBF conversion. Therefore, in moving from the
zero discharge option to the discharge option, air emissions would be
reduced by 450 tons per year. In addition, EPA estimates than 29,359
BOE less fuel would be used.
Other favorable non-water quality environmental impacts occur with
the elimination of the long term disposal of OBF-cuttings on shore,
because the pollutants present in OBF-cuttings may affect ambient air,
soil, and groundwater quality. EPA estimates that allowing discharge of
SBF-cuttings compared to zero discharge would decrease the amount of
OBF-cuttings disposed at land based facilities by 172 MM pounds
annually, and the amount injected by 40 MM pounds. The methodology used
to arrive at these numbers is described in the sections which follow,
and the results are discussed in more detail.
In consideration of the many non-water quality benefits with SBF-
discharge, EPA currently prefers to allow the controlled discharge of
SBF-cuttings despite some additional SBF-cuttings discharges that may
occur as a result of this rule. EPA's authority to consider the non-
water quality environmental impacts of its rule, therefore, forms the
primary basis in EPA's rejection of zero discharge of SBF-cuttings.
B. Method Overview
EPA estimated annual energy consumption (i.e., fuel usage), air
emissions, and solid waste generation rates from information on model
well characteristics and current drilling activity gathered from
industry, State, and Federal agency sources. This framework is based
upon the model well, well count, and control technology data that is
detailed in the compliance cost and pollutant reductions discussions of
today's notice (Section IX). EPA's calculations are based on the
following projections: wells drilled with SBF in the Gulf of Mexico
currently discharge SBF-cuttings containing an average 11 percent by
weight synthetic base fluid; under the discharge option SBF-cuttings
would retain an average 7 percent base fluid on cuttings; and of the
wells drilled with OBF 80 percent practice zero discharge by hauling
OBF-cuttings to shore for land-based disposal, and the remaining 20
percent inject on-site. In the context of the non-water quality
environmental impacts analysis, SBF wells using standard solids control
equipment and discharging SBF-cuttings at 11 percent retention are
defined as the baseline. Increases or decreases in non-water quality
environmental impacts are compared to this baseline. For example,
current OBF wells that EPA projects would convert to SBF in the
discharge option are assigned baseline impacts because these wells use
energy consuming technologies (i.e., transportation for disposal or
injection) beyond standard solids control equipment.
After establishing baseline impacts, EPA calculated impacts
resulting from compliance with the proposed discharge and zero
discharge options, details of which are given in the following
discussions. EPA then calculated the incremental impacts by subtracting
the compliance impacts from the baseline impacts.
The discussions below adopt the following acronyms for the four
model well types developed for well-specific analyses: DWD (deep-water
development), DWE (deep-water exploratory), SWD (shallow-water
development), and SWE (shallow-water exploratory).
C. Energy Consumption and Air Emissions for Existing Sources
1. Energy Consumption
a. Baseline Energy Consumption.--EPA's estimated non-water quality
environmental impacts for the discharge and zero discharge options, for
existing sources, are presented in Table VII-1. EPA set baseline energy
consumption according to SBF wells discharging SBF-cuttings at 11
percent retention of base fluid on wet cuttings. Table VII-1 shows,
therefore, that the baseline energy consumption (i.e., fuel usage) is
zero for existing Gulf of Mexico SBF wells, because increases or
decreases in fuel use and air emissions are compared to this level.
[[Page 5508]]
Table VII-1.--Summary Annual Baseline, Compliance, and Incremental Compliance, Non-Water Quality Environmental Impacts of SBF Cuttings Management from
Existing Sources
--------------------------------------------------------------------------------------------------------------------------------------------------------
Gulf of Mexico Offshore California Cook Inlet, Alaska Total
-----------------------------------------------------------------------------------------------------------------
Technology basis Air Air Air Air
emissions Fuel usage emissions Fuel usage emissions Fuel usage emissions Fuel usage
(tons/yr) (BOE/yr) a (tons/yr) (BOE/yr) a (tons/yr) (BOE/yr) a (tons/yr) (BOE/yr) a
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline Non-Water Quality
Environmental Impacts:
Currently SBF Discharge (11%
reten.).......................... 0 0 NA NA NA NA 0 0
Currently OBF Zero Discharge b.... 47.92 3,433 36.61 2,121 2.08 285 86.61 5,839
Compliance Non-Water Quality
Environmental Impacts:
Discharge Option (7% reten.)...... 12.54 3,035 0.76 187 0.01 4 13.30 3,226
Zero Discharge Option............. 338.55 24,125 NA NA NA NA 338.55 24,125
Incremental Non-Water Quality
Environmental Impacts Reductions
(Increases):
Discharge Option (7% reten.)...... 35.38 398 35.86 1,934 2.07 281 73.31 2,613
Zero Discharge Option............. (338.55) (24,125) 0 0 0 0 (338.55) (24,125)
--------------------------------------------------------------------------------------------------------------------------------------------------------
a BOE (barrels of oil equivalent) is the total diesel volume required converted to equivalent oil volume (by the factor 1 BOE = 42 gal. diesel) and the
volume of natural gas required converted to equivalent oil volume (by the factor 1,000 scf = 0.178 BOE).
b Baseline non-water quality environmental impacts from the 23 (20 percent) OBF wells that convert to SBF upon promulgation of today's proposed rule.
Baseline fuel usage rates for OBF wells in offshore California and
coastal Cook Inlet, Alaska derive from activities associated with
transporting waste drill cuttings to shore and land-disposing the
cuttings. For this analysis, EPA used the method developed to estimate
zero discharge impacts under the Offshore and Coastal Oil and Gas
Rulemakings. EPA used the volumes of drilling waste requiring onshore
disposal to estimate the number of supply boat trips necessary to haul
the waste to shore. Projections made regarding boat use included types
of boats used for waste transport, the distance traveled by the boats,
allowances for maneuvering, idling and loading operations at the drill
site, and in-port activities at the dock. EPA estimated fuel required
to operate the cranes at the drill site and in-port based on
projections of crane usage. EPA determined crane usage by considering
the drilling waste volumes to be handled and estimates of crane
handling capacity. EPA also used drilling waste volumes to determine
the number of truck trips required. The number of truck trips, in
conjunction with the distance traveled between the port and the
disposal site, enabled an estimate of fuel usage. The use of land-
spreading equipment at the disposal site was based on the drilling
waste volumes and the projected capacity of the equipment. The annual
baseline fuel usage in barrels of oil equivalents (BOE) is 2,121 BOE
for offshore California, and 285 BOE for coastal Cook Inlet.
In the Gulf of Mexico analysis, EPA projected that 20 percent of
OBF wells in shallow water would become SBF wells as a result of this
rule, and therefore they are included in the zero discharge analysis.
Baseline fuel usage rates (and all other impacts) for OBF wells in the
Gulf of Mexico are based on the assumption that 80 percent of these
wells use land-disposal for zero discharge and the remaining 20 percent
use on-site injection to dispose of OBF-cuttings. This assumption is
discussed further in Section IX of this Preamble, and in the
Development Document. Baseline fuel usage rates for zero discharge via
land-disposal were calculated using the same analysis used in the
offshore rule for California wells and coastal rule for Cook Inlet
wells. Baseline fuel usage rates for Gulf of Mexico wells that inject
waste cuttings onsite were calculated as the sum of the fuel usage for
the model turnkey injection system considered for the zero discharge
option, which consists of transfer equipment for moving cuttings,
grinding and processing equipment, and injection equipment. The per-
well fuel usage rates for wells that use on-site injection are weighted
averages of diesel usage rates and natural gas usage rates, according
to the estimate that 85 percent use diesel and 15 percent use natural
gas as primary power sources in the Gulf of Mexico. By multiplying the
average per-well baseline fuel usage rates by the projected annual
drilling activity for the four model wells in the Gulf of Mexico, EPA
calculated an annual baseline fuel usage of 3,433 BOE for the Gulf of
Mexico, and 5,839 BOE for all wells in the baseline.
b. Compliance Energy Consumption.--Energy consumption for the
discharge option was calculated by identifying the equipment and
activities associated with the operation of a vibrating centrifuge to
reduce the retention of the synthetic base fluid on drill cuttings from
an average 11 percent to seven percent, measured on a wet-weight basis.
Details regarding the technology basis for this option are presented in
Section VI of this Preamble, and in the Development Document. Using the
characteristics of the four model wells (see Section IX.B), EPA
calculated per-well energy consumption based on the horsepower demand
specified for the vibrating centrifuge by its manufacturer. The
horsepower demand was multiplied by the fuel usage rate and the hours
of operation required to drill the SBF section of the well, specific to
each model well type.
Since they are based on the same technology, the discharge option
per-well energy consumption rates are the same for the three geographic
areas, but vary based on the fuel source employed in each area. In the
Gulf of Mexico, industry sources recently estimated that approximately
85 percent of drilling operations use diesel oil as the primary fuel
source, and the remaining 15 percent use natural gas. Information
regarding fuel sources for the offshore California area indicates a
variety of sources, including diesel, natural gas, and for some
platforms, submerged electrical cables connected to shore-based power
supplies. For this analysis, it was determined that deep water wells in
offshore California use diesel as the primary fuel source, and shallow
water wells use natural gas. For coastal Cook Inlet wells, natural gas
was determined to be the primary fuel source, based on information
supplied by the industry both recently and submitted in the Coastal Oil
and Gas Rulemaking effort. Based on these determinations and projected
drilling activity estimates, EPA calculated the following annual
[[Page 5509]]
discharge option fuel usage rates for the three geographic areas: 3,035
BOE for the Gulf of Mexico, 187 BOE for offshore California, and 4 BOE
for Cook Inlet, for a total annual fuel usage rate of 3,226 BOE for
existing sources in the discharge option.
EPA calculated energy consumption for compliance with the zero
discharge option for the Gulf of Mexico wells that EPA estimates
currently discharge SBF cuttings, since these wells would need to
convert from discharge to zero discharge under this option. EPA
estimated fuel usage rates were estimated by identifying the equipment
and activities associated with two zero discharge technologies
currently in use in the Gulf of Mexico: 1) transporting waste cuttings
to shore-based land disposal sites; and 2) on-site injection. The
methods developed for calculating fuel usage for both these zero
discharge technologies are described above for baseline OBF wells.
While the same line-items were used to estimate impacts for the
transport and land-disposal technology scenario in all three geographic
areas, the per-well fuel usage rates vary between the three geographic
areas due to the various distances traveled by and trip frequencies of
boats and trucks in these areas. By multiplying the weighted average
per-well fuel usage rates by the projected annual drilling activity for
the four model wells in the Gulf of Mexico, EPA calculated a total
annual fuel usage rate of 24,125 BOE for existing sources in the zero
discharge option.
c. Incremental Compliance Energy Consumption. Incremental
compliance impacts are the difference between the baseline and the
compliance impacts, and indicate the amount by which baseline impacts
would be reduced with implementation of the compliance technologies
considered. Table VII-1 lists the total annual incremental fuel usage
rates for each geographic area for both the discharge and zero
discharge options. With the implementation of the discharge option,
there would be a reduction in fuel use of 2,613 BOE annually for
existing sources. This reduction is due to the elimination of transport
and land disposal equipment used to manage waste cuttings from baseline
OBF wells that switch to SBFs. Under zero discharge, there would be an
increase in fuel use of 24,125 BOE per year for existing sources. This
increase is due to the addition of transport and land disposal
equipment to manage waste cuttings from baseline SBF wells that
currently discharge cuttings.
2. Air Emissions
EPA estimated air emissions resulting from the operation of boats,
cranes, trucks, and earth-moving equipment necessary to dispose of
waste cuttings onshore, or the operation of on-site grinding and
injection equipment, by using emission factors relating the production
of air pollutants to time of equipment operation and amount of fuel
consumed. The baseline emissions, emissions reductions under the
discharge option, and emissions increases under the zero discharge
option are presented in Table VII-1.
D. Energy Consumption and Air Emissions for New Sources
Based on current drilling activity data and information provided by
industry sources, EPA projects that an estimated 19 new source SBF
wells will be drilled annually in the Gulf of Mexico, consisting of 18
deep water development wells and 1 shallow water development well. No
new source wells are projected for offshore California and coastal Cook
Inlet because of the lack of activity in new lease blocks in these
areas. New source wells are defined as those requiring substantial new
infrastructure, and exclude exploratory wells by definition (EPA, 1993;
EPA, 1996).
Table VII-2 lists the annual energy consumption (i.e., fuel usage)
and air emissions calculated for baseline, discharge, and zero
discharge option for new sources. The methods used to calculate the
per-well impacts for new source wells are the same as for existing
sources, described above. The analysis indicates that new source wells
in the discharge option will marginally increase fuel use and air
emissions above the baseline. This increase is due to implementation of
the model SBF recovery device such that, instead of discharging waste
SBF-cuttings at the baseline control level of 11 percent retention,
would discharge at 7 percent retention. In the zero discharge option,
applying zero discharge technologies increases fuel use and air
emissions. Both increments represent the use of energy-consuming
equipment above the baseline. However, the discharge option raises
energy consumption only slightly while the zero discharge option leads
to a large increase in energy consumption and corresponding air
emissions.
Table VII-2.--Summary Annual Baseline, Discharge, and Zero Discharge Non-
Water Quality Environmental Impacts of SBF Cuttings Management from New
Sources
------------------------------------------------------------------------
Gulf of Mexico
---------------------------
Technology basis Air
emissions Fuel usage
(tons/yr) (BOE/yr) a
------------------------------------------------------------------------
Baseline: Discharge (11% retention)......... 0 0
Compliance:
Discharge (7% retention).................. 1.28 311
Zero Discharge............................ 39 2,932
Incremental Reductions (Increases):
Discharge (7% retention).................. (1.28) (311)
Zero Discharge............................ (39) (2,932)
------------------------------------------------------------------------
a BOE (barrels of oil equivalent) is the total diesel volume required
converted to equivalent oil volume (by the factor 1 BOE = 42 gal
diesel) and the volume of natural gas required converted to equivalent
oil volume (by the factor 1,000 scf = 0.178 BOE).
E. Solid Waste Generation and Management
The regulatory options considered for this rule will not cause
generation of additional solids as a result of the treatment
technology. However, the quantity of SBF-cuttings discharged under the
discharge option will be traded for a nearly equal quantity of OBF-
cuttings disposed of onshore or injected onsite to comply with the zero
discharge option. Implementation of the discharge option will result in
reductions of solid waste currently disposed at land-based facilities
and by injection, due to the OBF wells converting to SBF wells. For
existing sources currently using OBFs, under the discharge option, the
annual amount of waste cuttings disposed at land-based facilities would
be reduced by 30 MM pounds, and the amount injected would be reduced by
4 MM pounds, for a total of 34 MM pounds. Implementation of the zero
discharge option by existing sources would result in an increase of 132
MM pounds of waste cuttings disposed onshore, and 33 MM pounds
injected, for a total of 165 MM pounds. Thus, under the discharge
option, for existing sources the total reductions in amount of waste
cuttings disposed of at land-based facilities would be 162 MM pounds,
and the total amount injected would be reduced by 37 MM pounds.
The new sources analysis considers only SBF wells that discharge
waste cuttings with 11 percent retention of synthetic base fluid on
cuttings, which under the discharge option would discharge at 7
percent. Therefore, under the discharge option the incremental amount
of waste cuttings disposed onshore or injected is zero. Under the
[[Page 5510]]
zero discharge option, EPA estimated that 10 MM pounds would be
transported to shore and 2.6 MM pounds would be injected, for a total
of 13 MM pounds disposed annually for new sources.
Combining the reductions from the discharge option with the
increases in the zero discharge option, for existing and new sources
combined, shows that the total effect of discharge versus zero
discharge reduces the amount of OBF-cuttings sent to shore for land
disposal by 172 MM pounds annually and reduces the amount injected by
40 MM pounds annually. Thus the total reduction in zero-discharge OBF-
cuttings waste is 212 MM pounds annually.
F. Consumptive Water Use
Since little or no additional water is required above that of usual
consumption, no consumptive water loss is expected as a result of this
rule.
G. Safety
EPA investigated the possibility of an increase in injuries and
fatalities that would occur as a result of hauling additional volumes
of drilling wastes to shore under the zero discharge option. EPA
acknowledges that safety concerns always exist at oil and gas
facilities, regardless of whether pollution control is required. EPA
believes that the appropriate response to these concerns is adequate
worker safety training and procedures as is practiced as part of the
normal and proper operation of oil and gas facilities.
EPA believes the preferred discharge option may marginally decrease
the number of accidents due to the decrease in supply vessel traffic,
as well as the decrease of crane usage to load and unload cuttings
boxes. However, EPA finds that these differences are not significant,
in light of the analysis of the following section on vessel traffic.
H. Increased Vessel Traffic
EPA estimated the amount of additional vessel traffic that would
result from the implementation of the preferred discharge option and
the zero discharge option. To measure increases or decreases in vessel
traffic, the current baseline level of supply boat frequency for wells
currently drilled with OBF was calculated using the numbers of boat
trips estimated as part of the energy consumption and air emissions
impact analyses described above.
To comply with the zero discharge option, EPA estimates that the
113 existing and new source wells in the Gulf of Mexico (GOM) currently
drilled with SBF would implement zero discharge technologies. Based on
the assumption that 80 percent of these wells would transport waste
drill cuttings to shore, an estimated total of 91 boat trips per year
would be required. No additional boat trips would be required in
California and Cook Inlet, Alaska, because these regions are currently
at zero discharge of SBF-cuttings.
Under the discharge option, 23 (20 percent) GOM wells, the 12
California wells, and the one Cook Inlet well, currently drilled with
OBF would convert to SBF usage, thereby eliminating the need for
hauling OBF cuttings to shore. Baseline supply boat trips per year were
estimated as follows: 18 trips for the 23 wells in the Gulf of Mexico
where 18 wells transport drill cuttings to shore and the other 5 inject
on-site; 12 trips for the 12 wells in offshore California; and 1 trip
for the well in coastal Cook Inlet. Therefore, EPA projects that supply
boat traffic would decrease by 31 boat trips per year. Compared to the
zero discharge option which led to 91 additional boat trips per year in
the GOM, the discharge option reduces boat traffic over the three
regions by 122 boat trips per year, and in the GOM by 109 boat trips
per year. As cited in the Offshore Oil and Gas Development Document, 10
percent of the total Gulf of Mexico commercial vessel traffic, or
approximately 25,000 vessels, service oil and gas operations.
Therefore, compared to the zero discharge option, the discharge option
decreases commercial boat traffic by 0.04 percent in the GOM. EPA does
not consider this decrease a significant impact.
VIII. Water Quality Impacts of Proposed Regulations
A. Introduction
EPA has evaluated the potential effects of the proposed regulation
on the receiving water environment. Consistent with the scope of the
rule, the analysis covers only those geographic areas where water-based
drilling fluids (WBFs) may be discharged under current regulations,
i.e., offshore waters beyond three miles from the shoreline, Alaska
offshore waters with no three-mile restriction, and the coastal waters
of Cook Inlet, Alaska.
Based on performance characteristics, SBFs are considered to be a
substitute for traditional oil-based drilling fluids (OBFs) using
diesel oil and mineral oil, but not for WBFs. For the water quality
impacts analysis, EPA has assumed that the future use of WBFs will be
in keeping with current practice, and that SBFs will replace
traditional OBFs at 20 percent of the wells where OBFs would otherwise
be used. EPA intends that ``whole'' SBFs will not be discharged, and
therefore only the drill cuttings and the adherent residual fluid will
be discharged. This is in contrast with the current regulation for WBF
drilling wastes, which allows for the controlled discharge of both
cuttings and whole fluids. Discharge of traditional OBF drilling wastes
to water is not allowed by current regulations and permits. OBF
drilling wastes are therefore injected into disposal wells or shipped
to shore for proper disposal.
Allowing the discharge of SBF-cuttings would make them, in many
cases, less expensive to use than OBFs, and thus would encourage the
use of SBFs. Changing practices from traditional OBF drilling/offsite
disposal to SBF drilling/onsite discharge is expected to produce
significant non-water quality environmental benefits (see Section VII).
However, since discharge of traditional OBFs is prohibited, switching
from OBF drilling/offsite disposal to SBF drilling/onsite discharge
would result in additional water quality impacts. Where SBF cuttings
are currently being discharged, the proposed discharge controls would
reduce the water quality impacts. EPA has evaluated the water quality
impacts of SBF discharges, and has used this analysis in balancing
today's proposal with non-water quality environmental impacts
associated with the use of OBFs. Based on this analysis, EPA prefers to
allow the controlled discharge of SBF cuttings and reduce non-water
quality environmental impacts.
The chemical composition (and for the most part, toxicity testing)
of various existing SBFs indicate that they are considerably less toxic
and less hazardous to human health than traditional OBFs. Therefore,
the water quality impacts from an accidental spill of SBFs would be
expected to be lower compared to a similar spill involving traditional
OBFs.
B. Types of Impacts
1. Pollutant Characterization
Although SBFs are not considered to be a replacement for WBFs, it
is useful to compare the two types of fluids, since the discharge of
WBFs is currently allowed. As with WBF discharges, SBF-cuttings
discharges will contain total suspended solids (TSS) associated with
the drill cuttings and solids of the drilling fluid, metals associated
with the drilling fluid barite and the geologic formation, and priority
and nonconventional pollutants associated
[[Page 5511]]
with potential contamination by formation (crude) oil. Some pollutants
of concern from the barite include priority metals such as arsenic,
chromium, copper, lead, mercury, nickel, and zinc, and nonconventional
pollutants such as aluminum and tin. Formation oil contamination may
include priority organics such as fluorene, naphthalene, phenanthrene,
and phenol, and nonconventional pollutants such as alkylated benzenes
and total biphenyls.
Compared to WBFs and associated cuttings, SBF-cuttings will have
additional pollutants associated with the synthetic base fluids
themselves. In general, these pollutants are long-chain hydrocarbons or
esters of vegetable fatty acids which present a significant organic
loading. They are considered non-conventional pollutants.
The principal water column impacts anticipated from SBF drilling
wastes are increased turbidity and toxicity. Turbidity is associated
with the discharged solids, and can negatively impact fish and biotic
productivity. Toxicity may arise from the waste stream pollutants that
leach into the water column. Previous modeling of offshore WBF
discharges indicates that these effects are localized and short-term
(on the order of hours). The additional organic pollutants comprising
the SBFs are not expected to exacerbate water column impacts, since
they generally are water non-dispersible and exhibit very low
solubility in water.
Laboratory and field studies indicate that the primary impacts from
SBF-cuttings discharges are associated with the benthic community.
These impacts include those associated with the discharge of WBFs,
i.e., smothering of sessile organisms, toxicity, and altered sediment
grain size, leading to reductions in abundance and diversity of the
benthic biota over a localized area. SBF-cuttings are expected to
produce additional impacts associated with the base fluid pollutants,
such as organic enrichment, anoxia resulting from biodegradation, and
potential increased toxicity. In nutrient-poor deep sea environments,
organic enrichment may alter the benthic community by increasing
overall biomass density.
Toxicity potential of SBFs seems better assessed through sediment-
phase tests than aqueous-phase tests, since SBFs are hydrophobic and
have strong self-adherence properties. Based on the chemical
composition of SBFs and on limited sediment-phase test data (five sets
of test data by different scientists using various sediment-dwelling
and water column-dwelling marine organisms), the potential for toxicity
varies among fluid types, but generally appears to be low. However,
some test results indicate that sediment toxicity of certain SBFs is
not reduced compared to OBFs.
Biodegradability is an important SBF parameter, since organic
enrichment and ensuing sediment oxygen depletion is expected to be a
dominant impact of SBF discharges. All SBFs have high theoretical
oxygen demands and are likely to produce a substantial sediment oxygen
demand as they degrade in the receiving environment.
The available information on the bioaccumulation potential of SBFs
is limited, consisting of six studies on octanol:water partition
coefficients (Pow) and two studies on tissue uptake in
experimental exposures. The limited data and the chemical composition
of SBFs suggest that existing SBFs do not pose a significant
bioaccumulation potential.
EPA intends to generate or obtain additional data regarding the
potential for toxicity, bioaccumulation, and persistence of SBFs,
through laboratory studies and seabed surveys at SBF-cuttings discharge
sites. The further work EPA intends to perform on laboratory testing is
detailed in Section VI of today's notice. Further intended seabed
surveys are discussed at the end of this section under the heading
``Future Seabed Surveys.''
2. Seabed Surveys
Past seabed surveys provide some insight into the fate and effects
of SBF discharges. Results of several seabed surveys are described
below.
a. EPA/Industry Seabed Survey.--In August 1997, EPA and industry
jointly conducted a seabed survey in the Gulf of Mexico at three
platforms on the central Louisiana continental shelf where SBF-cuttings
were discharged. The purpose of the survey was to conduct a preliminary
evaluation to determine the areal extent of observable impact. At the
Grand Isle site (water depth = 61 meters), 1,315 bbl (167 metric tons)
of internal olefin (IO) SBF were discharged on cuttings. Discharge
ceased 25 months prior to the survey. At the South Marshall Island site
(water depth = 39 meters), 94 bbl (12 metric tons) of linear alpha
olefin (LAO) and IO SBF were discharged on cuttings. Discharge ceased
11 months prior to the survey. At the South Timbalier site (water depth
= 33 meters), 2,390 bbl (304 metric tons) of IO SBF were discharged on
cuttings. Discharge ceased 10 months prior to the survey.
Sediment was sampled at stations from 50 to 150 meters away from
the platforms, with reference stations at 2,000 meters. Samples were
collected at each station for physical and chemical analysis. Samples
for biological analysis and toxicity testing were collected at selected
stations. The odor of hydrogen sulfide was observed in seven of the 61
samples collected near the platforms (within 150 meters), indicating
anoxic conditions. Although only a small fraction of the available
seabed area was sampled, the results indicate that detectable SBF
hydrocarbon (SBF-H.C.) concentrations were limited to within 50 to 150
meters of the platforms, with the highest concentrations (on the order
of 10,000 ppm) being within 50 meters of the platforms. Elevated SBF-
H.C. concentrations appeared to occur in a spotty, mosaic pattern
rather than in a continuous unbroken pattern around the platform.
Ten-day acute sediment toxicity tests were performed by the
industry coalition on six samples near the platforms. The tests were
performed using the amphipods Leptocheirus plumulosus and Ampelisca
abdita. With the exception of one sample, survivals of both organisms
exceeded 75 percent (survival of A. abdita was 62 percent in a sample
taken 100 meters from the Grand Isle platform). For all platforms, L.
plumulosus survivals were greater than those observed for the control
sediment (although control survival was extremely low). Average
survivals over all non-reference, non-control sediments were 92 percent
and 83 percent for L. plumulosus and A. abdita, respectively. Average
reference station sample survivals were 95 percent and 91 percent for
L. plumulosus and A. abdita, respectively. Average control sample
survivals were 65 percent and 83 percent for L. plumulosus and A.
abdita, respectively.
EPA also conducted sediment toxicity tests on the seabed survey
samples. Sample locations include the same ones as those tested by the
industry coalition, plus three additional locations around the Grand
Isle platform. For all platforms, survival of A. abdita indicated no
adverse toxicity beyond that demonstrated for the control sediment. L.
plumulosus test results demonstrated a high degree of toxicity (0--65
percent survival) within 150 meters of the Grand Isle platform, with
the higher toxicities at locations closer to the platform. Compared to
the Grand Isle site, L. plumulosus test results indicated much lower
toxicity near the South Marshall Island platform (83-92 percent
survival) and the South Timbalier platform (83-85 percent survival).
Average survival over all non-reference, non-control sediments were 60
percent and 85 percent for L. plumulosus and A. abdita, respectively.
[[Page 5512]]
Average reference station sample survivals were 88 percent and 87
percent for L. plumulosus and A. abdita, respectively. Average control
sample survivals were 95 percent and 87 percent for L. plumulosus and
A. abdita, respectively.
EPA also collected samples at the Grand Isle and South Marshall
Island sites for macroinfaunal analysis, but the samples have not yet
been analyzed.
b. Other Seabed Surveys.--There are limited biological assessment
data from seabed surveys around platforms where SBF-cuttings have been
discharged. Of the fourteen other sites where seabed surveys have been
performed, only five include biological analyses. Two of the sites are
in the Gulf of Mexico; the other three are in the North Sea.
One Gulf of Mexico study (1995) was performed at a platform in 39-
meter deep water where 354 bbl (45 metric tons) of a poly alpha olefin
(PAO) SBF was discharged on cuttings. Surveys were conducted nine days,
eight months, and two years after discharge ceased. Sediment was
sampled at stations from 25 to 200 meters away from the platform, with
reference stations at 2,000 meters. Eight months after discharge, the
total petroleum hydrocarbon (TPH) concentration in the sediment
decreased substantially (60 percent-98 percent) at all but the closest,
25-meter stations. It is uncertain how much of this decrease is
attributable to biodegradation, as opposed to sediment redistribution
and reworking. It appears that little further reductions in TPH
sediment concentration occurred between the 8th-month post-discharge
survey and the second-year post-discharge survey. Limited analysis of
the benthic fauna (performed in the second-year post-discharge survey
only) indicate significant differences (reduced abundance and richness)
at the 25-meter and 50-meter stations compared to reference stations.
Another Gulf of Mexico study (1998) was performed in a relatively
deep water environment in the northern Gulf, at a platform in 565-meter
deep water. Approximately 5,500 bbls (699 metric tons) of an SBF, using
a blend of 90 percent linear alpha olefin and 10 percent vegetable
ester as the base fluid, had been discharged on cuttings prior to the
first survey, which was conducted approximately four months after
discharge ceased. A second survey was performed approximately eight
months after the first survey (approximately one year after the first
series of discharges ceased). An additional 1,600 bbls (203 metric
tons) of SBF were discharged on cuttings two days prior to the second
survey.
Sediment was sampled out to 90 meters from the platform. High
sediment SBF concentrations (up to 198,000 ppm) suggest that the in-
situ biodegradation rate was lower than anticipated. Between the two
surveys, densities of polychaetes and nematodes increased
significantly, and the dominant taxon shifted from cyclopoid copepods
to polychaetes and nematodes. Biomass density was highest in the area
where the highest SBF concentrations were found. In the second survey,
the densities of polychaetes, cyclopoid copepods, and gastropods in
this area were approximately 40, 650, and 3,000 times higher than
background levels for northern Gulf of Mexico reference sites at
similar water depths. Fish densities in the vicinity of the platform
were approximately 3-10 times higher than background levels. The
analysis indicates that the SBF may be acting as a nutrient source and
thereby supporting increased biomass in a typically nutrient-poor deep
sea benthic environment.
One of the North Sea studies (1996) includes an impact study of the
discharge of 180 metric tons of an ester SBF at a Dutch well site in
30-meter deep water. Surveys occurred one, four, and eleven months
after discharge ceased. In each survey, the SBF was detected in the
upper 10 cm of sediment out to a distance of 200 meters from the
discharge site (the farthest distance sampled for sediment ester
concentration). During the 4th-month post-discharge survey, sediment
ester levels appeared to increase, apparently due to resuspension and
transport of contaminated sediment. Significant decreases of 65 percent
to 99 percent in sediment ester levels occurred between the 4th-month
and 11th-month post-discharge surveys. Effects on benthos abundance and
richness were more extensive; in the 4th-month post-discharge survey,
effects were noted at 500-meter stations (the farthest distance sampled
for biological assessment), with ``pronounced'' effects within 200
meters. Benthic analyses from the 11th-month post-discharge survey
indicated significant effects only out to 200 meters. Additionally,
recolonization and recovery were noted within the study area after 11
months.
Another North Sea study (1991) involved the discharge of 97 metric
tons of an ester SBF at a Norwegian well site in 67-meter deep water.
Surveys were conducted immediately, one year, and two years after
discharge ceased. Samples were taken out to 1,000 meters from the
platform. Sediment ester levels fell dramatically between sampling
events, with both maximum and average values within 1,000 meters
decreasing more than three orders of magnitude between the time-zero
and first-year post-discharge surveys, and more than five orders of
magnitude between the time-zero and second-year post discharge surveys.
Benthic organism abundance and richness were severely impacted out to
100 meters in the first survey (immediately post-discharge). Evidence
of minor macrobenthic community changes was seen in the second-year
post-discharge survey.
Another North Sea study (1992) examined the effects of the
discharge of 160 metric tons of an ether SBF at a Norwegian well site.
Surveys were conducted immediately, one year, and two years after
discharge ceased. Sediment samples were taken out to 200 meters from
the platform. Ether levels appeared to fall continuously, with mean
ether levels decreasing by factors of two-fold between the time-zero
and first-year post-discharge surveys, and ten-fold between the time-
zero and second-year post-discharge surveys. This degree of degradation
appears to be considerably less than that noted for the ester SBF site
noted above. The author interpreted this as indicating that a lag phase
occurred in the biodegradation of the ether SBF. (Laboratory
biodegradation testing using the solid phase test also shows that
ethers have a much slower degradation rate than vegetable esters.)
Benthos were analyzed at only four stations in the second-year post-
discharge survey; the author reported that the observed effects were
``remarkably weak''.
c. Conclusions.--There is limited field information upon which to
base broad conclusions about the potential extent of biological impacts
from SBF discharges. Based on seabed surveys, it appears that
significant biological impact zones may range from as little as 50
meters to as much as 500 meters from the platform initially, to as much
as 200 meters a year later. Generally, severe initial effects seem
likely within 200 meters of the discharge. The initiation of benthic
recovery seems likely within a year after discharge has ceased, and it
seems unlikely that recovery will be complete within two years (to
date, no post-discharge surveys have been performed beyond a two-year
period). The time scale of complete recovery from SBF discharges (and
oil and gas drilling and production platform activity in general) is
uncertain. Impact zones and recovery rates will be site-specific,
depending on factors such as water depth, current, temperature, and
[[Page 5513]]
seafloor energy, all of which affect the rate of degradation and
dispersion of the SBF components and drill cuttings. In nutrient-poor
benthic environments such as the deep sea, SBFs may serve as a nutrient
source and thereby increase overall biomass density.
C. Water Quality Modeling
To assess the water quality impacts of the regulatory options, EPA
modeled incremental pollutant concentrations, in the water column and
in the sediment pore water, at the edge of the 100-meter radius mixing
zone established for offshore discharges by CWA Section 403, Ocean
Discharge Criteria, as codified at 40 CFR Part 125 Subpart M. The
modeling was performed for the Gulf of Mexico, Offshore California, and
Cook Inlet, Alaska discharge regions. The modeling was performed for
each model well (shallow water exploratory, shallow water development,
deep water exploratory, and deep water development), as appropriate for
each discharge region, for current industry practice and each of the
two options:
(1) Current Practice = 11 percent base fluid retention on cuttings
(by weight on wet cuttings) with 0.2 percent crude contamination (by
volume in drilling fluid) .
(2) Discharge Option = seven percent retention on cuttings with 0.2
percent crude contamination.
(3) Zero Discharge.
The seven percent retention above is based on the long-term average
with the control technology of today's proposal, as detailed in Section
VI of today's notice. The 0.2 percent crude contamination is not based
on the regulatory limit but rather a concentration EPA estimates would
commonly be found in SBF discharged with cuttings.
EPA compared the modeled values to federal water quality criteria/
toxic benchmark recommendations for marine acute effects, marine
chronic effects, and human health effects via ingestion of organisms.
For the most part, individual modeled pollutant concentrations were
compared to the criteria for each pollutant. In the pore (interstitial)
water analysis, potential additive toxic effects of six of the metals
(cadmium, copper, lead, nickel, silver, and zinc) were accounted for by
converting the pore water concentrations to toxic units and summing
them. This approach is in accordance with EPA's proposed sediment
guidelines for these metals, which indicate that benthic organisms
should be acceptably protected if the sum of the Interstitial Water
Guidelines Toxic Units (IWGTUs) for these six metals is less than or
equal to one. (Alternatively, the benthic organisms should be
acceptably protected if the sum of the molar concentrations of
simultaneously extracted metals (SEM) for these six metals is less than
or equal to the molar concentration of acid volatile sulfide (AVS) from
the sediment.) The pollutant-specific IWGTU is defined as the dissolved
interstitial water concentration of the pollutant divided by the water
quality criterion (chronic value) for that pollutant.
EPA criteria/toxic benchmark recommendations are considered by the
States in developing water quality criteria for State waters. The
criteria are not steadfast standards in federal offshore waters, but
EPA takes them into account in making a determination of whether a
discharge will cause unreasonable degradation of the marine environment
(See 40 CFR Part 125.122(a)(10)). The modeled pollutants include only
those priority and nonconventional pollutants for which EPA has
established numeric marine water quality criteria. Concentrations of
TSS, synthetic base fluids, and some other constituents have therefore
not been modeled. However, EPA emphasizes that much of the anticipated
benefits of controlling SBF discharges lies in reducing discharge
quantities of TSS and oil and grease (including synthetic base fluids).
For example, based on model well scenarios, EPA projects that the
controlled discharge option will reduce discharges of total oil and
SBF-associated TSS (i.e., TSS associated with SBFs adhering to
cuttings) by 43 percent compared to current industry practice where
SBFs are currently being discharged. Reducing the discharge quantities
of these pollutants at existing SBF discharge sites is expected to
decrease the potential impact on the environment (particularly the
benthos) by reducing the severity of physical habitat alteration,
anoxia, and potential toxicity and bioaccumulation. Where operators
switch from OBF drilling/offsite disposal to SBF drilling/onsite
discharge, total pollutant loading to the aquatic environment will
increase.
EPA recognizes some limitations in this analysis. Due to a lack of
adequate modeling tools, the analysis does not quantify the effects of
smothering, physical habitat alteration, or anoxia. Additionally, the
analysis does not consider background pollutant concentrations or
pollutant loadings from other potential discharges, such as WBFs or
produced water. The analysis is conservative in that the pollutants are
assumed to be fully leached (to the extent that they are leachable in
accordance with their partitioning coefficients and leach percentages)
into the medium under consideration. That is, for the water column
analysis, EPA assumed that all leachable pollutant mass leaches into
the water column (with none left over for leaching into the pore
water). Likewise, for the pore water analysis, EPA assumed that all of
the leachable pollutant mass leaches into the pore water (without any
mass lost to the water column).
The modeled water column concentrations are based on existing
Offshore Operators Committee modeling of OBF-cuttings discharges, since
dispersion behavior of SBF cuttings is expected to be similar to that
of OBF-cuttings. EPA used median estimated dilution values (specific to
each discharge region) at the 100-meter mixing zone to calculate
predicted water column concentrations for pollutant discharges from the
model wells. Non-synthetic organic pollutants were assumed to be fully
dissolved in the water column. Effluent metal concentrations were
adjusted by pollutant-specific mean seawater leach percentage factors
to determine water column concentrations. The modeling indicates that
neither current industry practice nor the discharge option would result
in exceedances of any federal water quality criteria/toxic benchmarks
at the edge of the 100-meter mixing zone, for any of the modeled
discharge regions.
The modeled sediment pore water concentrations for the Gulf of
Mexico are based on sediment pollutant characterizations from five
field surveys of 11 wells (ten in the North Sea, one in the Gulf of
Mexico) where SBFs have been discharged. The California and Cook Inlet
analyses are also based on this approach, but data from two shallow
wells were eliminated to better represent discharge conditions in those
regions. Sediment synthetic concentrations at 100 meters from the
discharge point were taken or interpolated from each of the surveys. An
average sediment synthetic concentration was derived for each model
well, and the sediment concentration of each pollutant was calculated
based on the ratio of each pollutant to the synthetic material. Pore
water pollutant concentrations were then calculated based on mean
seawater leach percentages (for metals) and partition coefficients (for
organics). Organic pollutant partitioning was based on an average
fractional organic carbon content for sediment in each discharge
region.
[[Page 5514]]
Table VIII-1 lists the factors by which projected pore water
concentrations of certain pollutants would exceed federal water quality
criteria/toxic benchmarks for each regulatory scenario and model well
in the modeled discharge regions. EPA notes that these pollutants are
associated with the geologic formation and/or the barite used in all
drilling fluids, and are not specific to SBF discharges. Modeling of
current industry practice (with respect to SBF discharges only)
indicates that the pore water pollutant concentrations would exceed
some federal criteria/toxic benchmarks at the edge of the 100-meter
mixing zone in several model well scenarios. The modeling indicates
that, due to discharge limits on drilling fluid retention, the
discharge option would reduce pollutant pore water concentrations by 43
percent compared to current industry practice (where SBFs are currently
being discharged). The discharge option would thereby reduce the number
and magnitude of projected exceedances compared to current industry
practice (at existing SBF discharge sites). Zero discharge would
obviously eliminate any projected exceedances.
Table VIII-1.--Factors by Which Pore Water Pollutant Concentrations at the Edge of the 100-Meter Mixing Zone Would Exceed Federal Water Quality Criteria
Recommendations for Each Regulatory Option and Model Well a
--------------------------------------------------------------------------------------------------------------------------------------------------------
Shallow water Deep water
-----------------------------------------------------------------------------------------------
Development well Exploratory well Development well Exploratory well
Discharge region Pollutant -----------------------------------------------------------------------------------------------
Current Discharge Current Discharge Current Discharge Current Discharge
practice option practice option practice option practice option
--------------------------------------------------------------------------------------------------------------------------------------------------------
Gulf of Mexico.................... Arsenic............. 1.3 (c) 2.7 .......... 1.9 1.1 4.3 2.5
Chromium............ .......... .......... 1.7 .......... 1.3 .......... 2.8 1.6
Mercury............. .......... .......... .......... .......... .......... .......... 1.2 ..........
Metals Composite(b). 1.1 .......... 2.3 1.3 1.7 .......... 3.7 2.1
California........................ Arsenic............. .......... .......... Not applicable 1.2 .......... Not applicable
Metals Composite(b). .......... .......... Not applicable 1.1 .......... Not applicable
Cook Inlet, Alaska................ Arsenic............. .......... .......... Not applicable
Not applicable
Not applicable
Metals Composite(b). .......... .......... Not applicable
Not applicable
Not applicable
--------------------------------------------------------------------------------------------------------------------------------------------------------
a There would be no exceedances for any pollutants with the zero discharge option.
b Metals composite includes cadmium, copper, lead, nickel, silver, and zinc.
c Blanks indicate no exceedances are predicted.
D. Human Health Effects Modeling
EPA has also evaluated the effects of the current industry practice
and regulatory options on human health via consumption of finfish and
shrimp from affected fisheries. Pollutant concentrations in finfish
tissue (applicable to the Gulf of Mexico, offshore California, and Cook
Inlet discharge regions) and shrimp tissue (applicable to the Gulf of
Mexico and offshore California) were estimated based on the previously
described water quality modeling techniques. As with the water column
and pore water analyses, EPA considered only incremental loadings from
SBF discharges, irrespective of other discharges and background
concentrations. The analysis is based on water-only exposure of
organisms (i.e., it does not consider organism exposure through the
food web), and includes only those pollutants for which a
bioconcentration factor has been established. Thus, the analysis does
not project uptake of synthetic compounds or nonconventional
pollutants.
In assessing human health impacts, EPA considered a seafood intake
rate of 177 grams per day. This value represents the 99th percentile of
daily seafood intake (fresh/estuarine and marine, uncooked basis),
based on the Combined USDA 1989, 1990, and 1991 Continuing Survey of
Food Intakes by Individuals. This intake rate is reflective of high-end
consumers in the general population, and is also a reasonable default
value for subsistence fishers. For the shrimp analysis, the intake rate
was adjusted by the estimated percent of shrimp catch affected by SBF-
cuttings discharges. The finfish intake rate was not adjusted, due to
lack of data on affected finfish landings. The finfish intake rate is
therefore much more conservative than the shrimp intake rate, as all
consumed fish are assumed to be affected by SBF-cuttings discharges.
To estimate potential non-cancer (toxic) effects, EPA calculated
the Hazard Quotient for each pollutant. The Hazard Quotient is the
estimated pollutant intake rate divided by the pollutant-specific oral
reference dose, which represents a level that is protective of human
health with respect to toxic effects. A Hazard Quotient greater than
one indicates that toxic effects may occur in exposed populations. For
arsenic (a human carcinogen), EPA also estimated the lifetime marginal
risk of developing cancer, using the EPA-developed, pollutant-specific
potency slope factor. For purposes of this analysis, a risk level of 1
x 10-6 is considered to be acceptable.
The finfish exposure assessment is based on incremental pollutant
exposures within 100 meters of each platform. The spatial extent of
exposure within this area was derived using average dilution values
(specific to each discharge region) within the mixing zone, based on
existing Offshore Operators Committee modeling of OBF-cuttings
discharges. Water column pollutant concentrations were projected using
leach percentages and partitioning coefficients, and finfish uptake was
calculated based on pollutant-specific bioconcentration factors and a
catch-weighted average lipid content of 2.14 percent.
The modeling indicates that, due to discharge limits on drilling
fluid retention, the discharge option would reduce pollutant tissue
concentrations in finfish by 43 percent compared to current industry
practice (where SBFs
[[Page 5515]]
are currently being discharged). Neither current industry practice nor
the discharge option would result in toxic human health impacts or
excess cancer risk under a 99th percentile consumption scenario, for
any of the modeled discharge regions.
For the shrimp exposure assessment in the Gulf of Mexico and
offshore California, EPA estimated an impact area based on field survey
data and an assumed threshold concentration of 100 ppm for synthetic
fluid in sediment. Sediment pollutant concentrations for each model
well were calculated based on one year's worth of cuttings discharges,
assuming an affected depth of 5 cm and uniform distribution of cuttings
over the impact area. Pore water pollutant concentrations were
projected using leach percentages and partitioning coefficients, and
shrimp uptake was then calculated based on pollutant-specific
bioconcentration factors and a shrimp lipid content of 1.1 percent.
The modeling indicates that, due to discharge limits on drilling
fluid retention, the discharge option would reduce pollutant tissue
concentrations in shrimp by 43 percent compared to current industry
practice (where SBFs are currently being discharged). Neither current
industry practice nor the discharge option would result in toxic human
health impacts or excess cancer risk under a 99th percentile
consumption scenario, for either of the modeled discharge regions.
E. Future Seabed Surveys
1. Ocean Discharge Criteria
Permits authorizing the discharge of SBF-cuttings are required to
(a) meet technology-based requirements to set the control floor, and
(b) meet section 403(c) of the Clean Water Act (CWA) Ocean Discharge
Criteria, or, in state waters of Cook Inlet, Alaska, meet state water
quality criteria. Today's notice proposes the technology-based
discharge controls. While not a part of today's proposed rule, the
following briefly describes the CWA 403(c) requirements and the future
seabed surveys EPA thinks should occur, based on currently available
information, to satisfy these permit requirements. The seabed surveys
that industry has planned to conduct are also presented.
The nature, extent and duration of seabed surveys required by
discharge permits may increase or decrease as further information is
gathered, and any monitoring requirement shall be decided by the EPA or
delegated state permitting authority. A decision that sufficient seabed
survey information has been gathered in one region does not constitute
grounds that further seabed surveys are no longer required in other
regions.
For ocean discharges, the ambient environmental effect information
needed to satisfy EPA permit requirements is specified in Clean Water
Act section 403(c), Ocean Discharge Criteria, as codified at 40 CFR
Part 125, subpart M. This subpart establishes guidelines for issuance
of National Pollutant Discharge Elimination System (NPDES) permits for
the discharge of pollutants from a point source into the territorial
seas, the contiguous zone, and the oceans. These criteria require that
a determination be made whether a discharge will cause unreasonable
degradation to the marine environment based on several considerations,
including the quantities, composition and potential for bioaccumulation
or persistence of the pollutants to be discharged, and considerations
relating to the importance and vulnerability of the potentially exposed
biological communities and human health (see 40 CFR Part 125.122).
If there is insufficient information to determine prior to issuing
the permit that there will be no unreasonable degradation to the marine
environment, the Ocean Discharge Criteria require that a monitoring
program be specified. This monitoring program must be sufficient to
assess the impact of the discharge on water, sediment, and biological
quality including, where appropriate, analysis of bioaccumulative and/
or persistent impact on aquatic life (see Sec. 125.123 (d) (2)).
According to Sec. 125.123 (c) (1) the discharge may not cause
irreparable harm to the marine environment during the period in which
monitoring is undertaken. If data gathered through monitoring indicate
that continued discharge may cause unreasonable degradation, the
discharge must be halted or additional permit limitations established.
2. EPA Suggestions for Monitoring Seabed Effects
EPA thinks that currently there is insufficient information to
determine that there will be no unreasonable degradation to the marine
environment. The Ocean Discharge Criteria, therefore, require that a
monitoring program be specified in permits allowing the discharge of
SBF-cuttings. The ambient environmental studies should monitor the rate
of seabed recovery around several offshore and coastal platforms where
SBF-cuttings have been discharged. Sites should be selected to include
both deep water and shallow water locations, and should investigate the
different types SBFs, according to base fluid, which the permits may
allow.
A detailed study may investigate baseline contaminants and benthic
invertebrate analysis, disappearance of SBF base materials over time,
toxicity of sediment over time, and rate of recolonization by benthic
organisms. Desired endpoints include impacts to benthos, sediment
characterization, and contribution to hypoxia.
To characterize the seabed survey site, detailed discharge
information should be gathered on the platform level. This information
should include the dates, prevailing current during discharge, and
amounts, for all discharges: WBF, WBF-cuttings, and SBF-cuttings. The
WBF and SBF formulations should also be provided. As a detail to the
SBF-cuttings discharge quantities, the determination of quantity of
synthetic material discharged should also be provided.
3. Industry's Plans for Seabed Surveys
EPA understands that the industry is planning a cooperative effort
to address the CWA 403(c) requirements in the GOM. Industry
representatives have told EPA that their cooperative seafloor study
would include a review of historical data on SBF usage on the shelf and
slope, and these data would be analyzed to select a representative
series of platforms. The cooperative effort plans that three cruises
would be conducted to evaluate equipment and sampling strategies,
delineate cuttings deposition profiles (areal extent as well as
thickness profile), determine SBF concentrations with depth and
distance from source, and to determine if zone of biological influence
can be determined. It is anticipated that most of the study sites
(e.g., 6-12) locations would be on the shelf, and one or two would be
located in deepwater. However, EPA may recommend that more deepwater
surveys be conducted, in proportion to the total number of SBF wells
drilled in the deepwater versus the shallow water. Parameters to be
considered in platform selection included type and volume of synthetics
released, number of wells drilled, water depth, shunt depth, and length
of time since last discharge. The cooperative effort plans that a
combination of side scan sonar, via remotely operated vehicle cameras,
and physical grab sampling would be used to determine cuttings
deposition. Mineralogy and sediment chemistry are planned to verify
cuttings and SBF presence. Oxygen measurements and relative percent
difference layer determinations are planned to evaluate SBF-induced
anoxia. Biological sampling would be conducted at
[[Page 5516]]
selected sites to evaluate ability to measure community structure
changes relative to drilling discharges. The deepwater location(s)
(between 500-1,200 m) would be sampled and surveyed by the remotely
operated vehicle to assess deepwater deposition and effects.
IX. Cost and Pollutant Reductions Achieved by Regulatory
Alternatives
A. Introduction
This section presents EPA's methodology and results for estimating
the compliance costs and pollutant reductions for the discharge and
zero discharge options. EPA calculated costs and loadings on a model
well basis, and determined total costs and loadings by multiplying the
model well values by the number of wells. Since this is a differential
analysis, the only wells, pollutants, and costs considered are those
that are expected to change as a result of this proposed rule were it
to become a final rule. Therefore, wells currently drilled with SBF are
considered in the analysis, and also OBF wells that EPA anticipates
will convert to SBF upon completion of this rule. However, wells
currently using OBF and not converting to SBF would not incur costs or
realize savings in the analysis. EPA assumed that only those wells
using SBF or OBF currently would potentially use SBF in the future, and
so wells drilled exclusively with WBF are not treated as incurring any
costs or realizing any cost savings in this analysis. Also, of the
wells that are in the analysis because they use SBFs or OBFs, the upper
sections of the well that are drilled with WBF are not associated with
any costs or savings in the analysis.
B. Model Wells and Well Counts
EPA developed model well characteristics from information provided
by the American Petroleum Institute (API) to estimate costs to comply
with, and pollutant reductions resulting from, the proposed discharge
option and the zero-discharge option. API provided well size data for
four types of wells currently drilled in the Gulf of Mexico (GOM);
development and exploratory in both deep water (i.e., greater or equal
to than 1,000 feet) and shallow water (i.e., less than 1,000 feet). The
following text refers to these wells by the acronyms DWD (deep-water
development), DWE (deep-water exploratory), SWD (shallow-water
development), and SWE (shallow-water exploratory).
The model well information from API provided length of hole drilled
for successive hole diameters, or intervals. From this, EPA calculated
the hole volume for the well intervals that reportedly used SBF or OBF.
For the four model wells and assuming 7.5 percent washout of the hole,
EPA determined that the volumes of these SBF (or OBF) well intervals
were, in barrels, 565 for SWD, 1,184 for SWE, 855 for DWD, and 1,901
for DWE.
EPA gathered information from the Department of Interior Minerals
Management Service (MMS), the Texas Railroad Commission and the Alaska
Oil and Gas Commission, to estimate the number of wells drilled
annually in each of the three regions where drilling is currently
active and drilling wastes may be discharged. To forecast the number of
wells drilled annually EPA averaged the number of wells drilled in
1995, 1996, and 1997. Based on information from the industry, MMS, and
DOE, EPA then applied the following projections to determine the number
of wells drilled by drilling fluid type:
(i) On a drilling performance basis SBF is equivalent to OBF.
(ii) Development and exploratory wells have equal requirements for
SBF/OBF performance.
(iii) In GOM as a whole, 10 percent of all wells use SBF, 10
percent use OBF, and 80 percent use WBF exclusively. However, no OBF is
used in the deepwater due to the potential of spills, and due to higher
performance requirements 75 percent of all wells in GOM deep water are
drilled with SBF. The remaining 25 percent are drilled exclusively with
WBF.
(iv) In offshore California and coastal Cook Inlet, Alaska, OBF is
used in the same frequency as SBF/OBF in the GOM (75 percent of wells
in deep water and 13.2 percent of wells in shallow water). The
remainder of wells use WBF exclusively and no SBF is used.
Also based on information from the industry, MMS, and DOE, EPA
determined the following concerning the conversion of SBF to OBF and
vice versa:
(i) For the discharge option, 20 percent of GOM OBF wells convert
to SBF, and all OBF wells are in the shallow water. All offshore
California and Cook Inlet, Alaska OBF wells convert to SBF.
(ii) For the zero discharge option, shallow water GOM SBF wells
convert to OBF. However, deep water GOM SBF wells do not convert,
because SBFs provide advantages in terms of eliminating OBF spills in
the event of riser disconnect. Offshore California and Cook Inlet,
Alaska OBF wells remain OBF wells.
Details of the how EPA made these determinations are provided in
the Development Document.
Table IX-1 presents the total number of wells that EPA estimates
will be drilled annually, by drilling fluid, for both the discharge
option and the zero discharge option. EPA has distinguished wells as
either ``existing'' sources of drill cuttings for BPT, BCT and BAT cost
and pollutant reductions analysis, or ``new'' sources of drill cuttings
for NSPS cost and reductions analysis.
Table IX-1.--Estimated Number of Wells Drilled Annually per Regulatory Option by Drilling Fluid
----------------------------------------------------------------------------------------------------------------
Shallow water (<1,000 Deep water (>1,000 ft)
ft) --------------------------
Type of well -------------------------- Total
Develop. Explor. Develop. Explor.
----------------------------------------------------------------------------------------------------------------
Gulf of Mexico:
Baseline All Wells \1\..................... 645 358 48 76 1127
Baseline SBF Wells......................... 13 7 36 57 113
Discharge Option SBF Wells................. \2\ 28 15 \3\ 36 57 136
Zero Discharge Option SBF Wells............ 0 0 36 57 93
Offshore California:\4\
Baseline All Wells......................... 11 0 15 0 26
Baseline OBF Wells......................... 1 0 11 0 12
Discharge Option SBF Wells................. 1 0 11 0 12
Coastal Cook Inlet, Alaska:\4\
Baseline All Wells......................... 7 1 0 0 8
Baseline OBF Wells......................... 1 0 0 0 1
[[Page 5517]]
Discharge Option SBF Wells................. 1 0 0 0 1
----------------------------------------------------------------------------------------------------------------
\1\ While this table lists total number of wells, the only wells included in the analysis are those affected by
this rule: SBF wells or wells converting from OBF to SBF in discharge option or converting from SBF to OBF in
zero discharge option.
\2\ EPA assumes that 95 percent of GOM shallow water development wells of this analysis are existing sources,
and 5 percent are new sources (equals one new source well).
\3\ EPA assumes that 50 percent of GOM deep water development wells of this analysis are existing sources, and
50 percent are new sources (equals 18 new source wells).
\4\ EPA assumes all offshore California and Cook Inlet, Alaska, wells are existing sources, and in discharge
option all OBF wells convert to SBF wells.
By multiplying the compliance costs and discharge loadings
determined from the model well analysis, EPA calculated the total cost
to the industry and the reduction in pollutant loadings, as detailed in
the following sections.
C. Method for Estimating Compliance Costs
1. Introduction and Summary
The costs considered as part of the compliance cost analysis are
only those that EPA believes will be incurred as a result of today's
rule. These include costs and savings associated with the discharge,
disposal, and recovery of SBF and OBF, costs associated with the
technologies used to control and manage waste drill cuttings under the
discharge and zero discharge options, and monitoring costs.
For each option and each geographic area, EPA estimated baseline
costs from current industry waste management practices. Following this,
EPA estimated the cost to comply with each option of today's rule. EPA
then calculated the incremental compliance costs, or the difference
between baseline costs and estimated compliance costs. Table IX-2 lists
the total annual baseline, compliance, and incremental compliance costs
calculated in each geographic area for both the discharge and zero
discharge regulatory options.
As the values in Table IX-2 show, EPA estimates that today's
proposed discharge option provides a savings to the industry of over $7
MM annually. Savings occur in the GOM among wells currently using SBF
because, according to information available to the EPA, the value of
SBF recovered by the model solids separation technology is $8.1 MM,
while the cost of implementing this technology is only $3.1 MM. Thus,
this regulatory requirement leads to an annual net savings of $5.0 MM.
Savings in the GOM also occur for the OBF wells that switch to SBF,
because the increased cost of SBF is less than the savings in disposal
costs for OBF-cuttings. However, EPA has assumed that only 20 percent
to the wells currently drilled with OBF in the GOM will switch to SBF
because of the risk of losing more valuable SBF downhole. These OBF
wells that convert are in the shallow water. EPA determined that any
deep water well operating in the Gulf of Mexico that prefers to use
SBFs has already converted to SBF. Savings also result in offshore
California and Cook Inlet, Alaska when OBF wells convert to SBF wells,
again because the increased cost of SBF is less than the savings in
disposal cost of OBF-cuttings. In these areas, EPA assumed that all OBF
wells switch to SBF because of more difficult and expensive zero
discharge options for OBFs in these areas, and air quality
considerations in California.
Table IX-2.--Summary Annual Baseline, Compliance, and Incremental Compliance Costs for Management of SBF
Cuttings, Existing and New Sources
[1997$/year]
----------------------------------------------------------------------------------------------------------------
Offshore Cook Inlet,
Technology basis Gulf of Mexico California Alaska Total
----------------------------------------------------------------------------------------------------------------
Baseline Costs:
Discharge with 11% retention of base
fluid on cuttings...................... $21,315,375 (\1\) (\1\) $21,315,375
Zero Discharge (current OBF-drilled
wells only)............................ 2,821,816 $2,157,023 $207,733 5,186,572
Total Baseline Costs per Area........... 21,935,466 2,157,023 207,733 24,300,222
Compliance Costs:
Discharge with 7% retention of base
fluid on cuttings...................... 17,582,675 1,647,883 115,467 19,346,025
Zero Discharge via land disposal or on-
site injection......................... 29,873,689 0 0 29,873,689
Incremental Compliance Costs (Savings):
Discharge Option........................ (6,554,516) (509,140) (92,265) (7,155,921)
Zero Discharge Option................... 8,558,314 0 0 8,558,314
----------------------------------------------------------------------------------------------------------------
\1\ Not applicable.
To summarize the effects of today's proposed rule, the values
listed in Table IX-2 above include both existing and new sources. The
values for new sources alone are provided below in Table IX-3. The
values for existing sources alone may be obtained by subtracting these
values from the corresponding values in Table IX-2.
As shown in Table IX-1, EPA estimated that new source wells are
located only in the Gulf of Mexico because of the lack of activity in
new lease blocks in offshore California and coastal Cook Inlet. New
source wells are defined in the offshore guidelines, 40 CFR Part
435.11(q), and exclude exploratory wells by definition (EPA, 1993; EPA,
1996).
[[Page 5518]]
Table IX-3.--Summary Annual Baseline, Compliance, and Incremental Compliance Costs for Management of SBF
Cuttings from New Sources
[1997/year]
----------------------------------------------------------------------------------------------------------------
Technology basis Costs (savings)
----------------------------------------------------------------------------------------------------------------
Baseline Costs.......................... Discharge with 11% retention of base fluid on $2,201,725
cuttings.
NSPS Compliance Costs................... Discharge with 7% retention of base fluid on 1,632,125
cuttings.
Zero Discharge via land disposal or on-site 3,796,143
injection.
Incremental NSPS Compliance Costs....... Discharge with 7% retention of base fluid on (569,600)
cuttings.
Zero Discharge via land disposal or on-site 1,594,418
injection.
----------------------------------------------------------------------------------------------------------------
The NSPS cost analysis consists of the same line-item costs as in
the analysis for existing sources, with the exception that retrofit is
not necessary on new platforms. The baseline for NSPS costs differs
from the baseline for existing sources in that it includes only SBF
wells that discharge cuttings and does not include any OBF wells
practicing zero discharge.
2. Baseline Costs: Current Industry Practice
As noted above, the only cost elements included in the baseline are
those that EPA anticipates will change as a result of the rule. The
line items in the baseline cost analysis for those Gulf of Mexico wells
that currently drill with SBF consist of the cost of SBF lost with the
discharged cuttings and the cost of the currently-required SPP toxicity
monitoring test. The baseline analysis for currently discharging wells
assumes the cuttings are being treated by standard solids control
equipment to an average 11 percent retention of synthetic material
(base fluid) on the cuttings, on a wet-weight basis. As detailed in
Section VI of today's notice and the Development Document, this
baseline level of treatment is derived from data submitted in a report
prepared for the American Petroleum Institute (API) (Annis, 1997). No
baseline costs are attributed to the operation of solids control
equipment that are standard in all drilling operations.
For existing sources, the unit baseline cost for wells that
currently use SBF is $82/bbl. The unit baseline costs for SWD and SWE
wells currently drilled with OBF are $96/bbl and $91/bbl, respectively.
The development of the baseline costs for OBF wells is detailed under
Section IX.C.4 ``Zero Discharge Compliance Costs.'' Table IX-2 lists
the total baseline costs for each geographic area.
The unit baseline cost for the new source wells is $82/bbl for both
DWD and SWD wells, and the total baseline cost is $2.2 MM.
In offshore California and coastal Cook Inlet, Alaska, current
industry practice is zero discharge of OBF-cuttings. The line-item
costs of these wells include costs for transporting and disposing of
waste drill cuttings at commercial land-based disposal facilities, and
the cost of the drilling fluid that adheres to and is disposed with the
cuttings. EPA assumes that the drilling fluid lost with OBF-cuttings is
a mineral oil-based fluid. For current industry practice,
transportation of OBF-cuttings in the offshore California analysis
consists of hauling via supply boat followed by trucking to a land-
based facility. Transportation for the Cook Inlet analysis also
consists of supply boats followed by trucks that haul the waste
cuttings to a land-based disposal facility. However, due to the limited
availability of disposal facilities in the Cook Inlet area, costs were
developed for hauling the waste to a facility in Oregon. This approach
to zero-discharge cost estimating for Cook Inlet was adopted from the
Coastal Oil and Gas Rulemaking effort (EPA, 1996).
The unit baseline costs in offshore California are $128/bbl for DWD
wells and $131/bbl for the SWD wells. The unit baseline cost for the
model Cook Inlet well is $218/bbl. Again, multiplying the unit costs by
the volume of waste cuttings for each model well type and by the
numbers of wells estimated to be drilled annually in each category
provides the total annual baseline costs for each region. The total
annual baseline costs for offshore California and Cook Inlet are $2.2
MM and $0.2 MM, respectively (see Table IX-2).
3. Discharge Option Compliance Costs
The discharge option compliance cost analysis estimates the cost to
discharge SBF-cuttings following secondary treatment by a solids
control device that, when added on to other standard solids control
equipment, reduces the average retention from 11 percent to 7 percent
base fluid on wet cuttings. Line-item costs in the discharge option
analysis consist of: a) costs associated with the use of an add-on
solids control device, b) cost to retrofit platform space to
accommodate the device, c) the value of the SBF discharged with the
cuttings, and d) the cost of performing the waste monitoring analyses
of today's proposal.
The wells in the discharge analysis for the Gulf of Mexico consist
of those that are currently drilled with SBF and discharging SBF-
cuttings, and those currently drilled using OBF that EPA estimates will
convert to SBF. The cost of the add-on technology is the daily rental
cost for the vibrating centrifuge device on which the seven percent
retention is based. The rental cost includes all equipment, labor and
materials, and was quoted by a Gulf of Mexico operator who used the
device in an offshore demonstration project (Pechan-Avanti, 1998).
Retrofit costs were assigned to all existing sources but not to new
sources. Analytical monitoring costs are included for the proposed
crude oil contamination of drill cuttings test and retort analysis for
SBF retention on cuttings.
For existing sources, based on the above line-item costs, the unit
discharge option costs for DWD and DWE wells are $74/bbl and $72/bbl,
respectively. The unit discharge option costs for the SWD and SWE wells
are $77/bbl and $74/bbl, respectively. The total annual discharge
compliance cost for existing source Gulf of Mexico wells is $16 MM (see
Table IX-2). The discharge option unit costs for new source wells are
$73/bbl for DWD wells and $75/bbl for SWD wells, and the total
discharge option cost is $1.6 MM.
The compliance cost analyses for offshore California and coastal
Cook Inlet, Alaska consist of the same line items: daily rental of the
add-on vibrating centrifuge, retrofit space to accommodate the add-on
equipment, cost of SBF lost with discharged cuttings, and analytical
costs for proposed waste monitoring tests. The costs for these items
are the same as those estimated for the Gulf of Mexico adjusted higher
using geographic area cost multipliers developed in the Offshore Oil
and Gas Rulemaking effort (EPA, 1993). Geographic area cost multipliers
are the ratio of equipment installation costs in a particular region
compared to the costs for the same equipment installation in the Gulf
of
[[Page 5519]]
Mexico. The cost multipliers for offshore California and Cook Inlet are
1.6 and 2, respectively. The unit discharge option costs for offshore
California wells are $118/bbl for DWD wells and $122 for SWD wells. The
unit discharge option cost for the Cook Inlet SWD well is $147/bbl. The
total annual discharge option compliance costs for offshore California
and Cook Inlet are $1.6 MM and $0.1 MM, respectively, and the total
annual industry-wide compliance cost for the discharge option is $17.7
MM, as shown in Table IX-2.
4. Zero Discharge Option Compliance Costs
The zero discharge compliance cost analysis includes Gulf of Mexico
wells identified as currently being drilled with SBF. The method
presented in this section was also applied to baseline OBF wells, as
mentioned in the baseline costs section. The wells included in the
offshore California and Cook Inlet analyses, and some shallow water
Gulf of Mexico wells (i.e., those wells currently drilled with OBF) do
not incur costs in the zero discharge option because they are at zero
discharge in the baseline. Furthermore, the population of wells
currently drilled with SBF is divided into those that are assumed to
continue using SBF under zero discharge requirements due to other
concerns (i.e., spills as a result of riser disconnect), and those that
would convert to OBF under zero discharge requirements due to the
economic incentive of a less costly waste management practice (i.e.,
all shallow water wells). This division is shown in Table IX-1.
Per-well zero discharge costs incorporate the assumption that, of
all zero discharge cuttings generated in the Gulf of Mexico, 80 percent
is hauled to shore for land-based disposal and 20 percent is injected
on-site. Preliminary information gathered regarding the use of on-site
injection in the Gulf of Mexico is inconsistent between sources,
ranging from an estimated 10 percent to as much as 66 percent (Veil,
1998). Additional information indicates that, while some operators have
expressed concern over uncertainties related to injection (e.g., the
ultimate fate of the injected wastes and the costs associated with
unsuccessful injection projects), interest in on-site injection has
increased throughout the industry since the time of the Offshore Oil
and Gas Rulemaking, and continues to grow. The Agency therefore
solicits information regarding the number of wells that use on-site
injection, the volume of drilling waste injected, the per-well and per-
barrel costs, and the frequency of unsuccessful injection projects.
Line-item costs in the land disposal zero discharge analysis
include commercial disposal facility costs, container rental costs,
supply boat costs, and value of drilling fluid retained on cuttings.
Commercial disposal facility costs were obtained from the major oil
field waste management companies serving the Gulf of Mexico industry.
Cuttings container size and rental rate were obtained from vendors. All
wells in the analysis are assumed to have acquired the retrofit space
needed to store an average of 12 cuttings boxes as part of the Offshore
Oil and Gas Rulemaking effort (EPA, 1993), and therefore do not incur
retrofit costs in this analysis. The value of retained drilling fluid
is based on mineral oil OBF ($75/bbl) for shallow water wells (assuming
they all convert to OBF under zero discharge requirements), and
internal olefin SBF (at $200/bbl) for deep water wells (assuming they
all still use SBF under zero discharge requirements). The unit land-
disposal cost varies by model well type: $148/bbl for DWD wells, $106/
bbl for DWE wells, $102/bbl for SWD wells, and $96/bbl for SWE wells.
Unit disposal costs vary by well type because the amount of time it
takes to fill the disposal ship varies by well type, and the cost for
the disposal ship is per daily rate.
Line-item costs in the on-site injection zero discharge analysis
include the day rate rental cost for a turnkey injection system, and
lost drilling fluid costs. The injection system cost includes all
equipment, labor, and associated services. The unit on-site injection
cost is $121/bbl for deep water wells, and $71/bbl for shallow water
wells.
The zero discharge compliance cost is the weighted average assuming
80 percent of wells use land disposal and 20 percent of wells use on-
site injection to achieve zero discharge. For existing sources, the
weighted average unit cost for zero discharge for the model wells is as
follows: $143/bbl for DWD wells, $109/bbl for DWE wells, $96/bbl for
SWD wells, and $91/bbl for SWE wells. The total annual zero discharge
compliance cost resulting from this analysis is $26.1 MM (see Table IX-
2).
For new sources, the weighted average unit costs are the same as
for existing sources: $143/bbl for DWD wells and $96/bbl for SWD wells.
The total zero discharge cost for new sources is $3.8 MM/year.
5. Incremental Compliance Cost
The incremental compliance cost is the difference between the
baseline and the compliance cost, as presented in Table IX-2. The
overriding factor in the Gulf of Mexico incremental discharge option
cost is that, according to EPA analysis of SBF baseline wells, the
value of the recovered SBF is greater than the cost of implementing the
vibrating centrifuge model technology. This gives a net savings of $5.0
MM/year. A saving of $0.94 MM/year is also realized when existing wells
currently using OBF convert to using SBF. EPA assumed for this
calculation that 23 of the 112 OBF wells, or 20 percent, would convert.
All of these are considered existing sources. Combining these two gives
a total savings of $5.9 MM for Gulf of Mexico existing source wells in
the discharge option.
Incremental discharge option costs for existing sources in offshore
California and coastal Cook Inlet, Alaska include savings incurred as
wells move from the zero discharge baseline to discharge, and increased
cost of SBF over the baseline OBF cost. For both of these areas, the
net incremental discharge compliance cost is negative, resulting in
savings of $509,000/year for offshore California and $92,000/year for
coastal Cook Inlet. Combined with the Gulf of Mexico savings, the total
annual savings for existing sources in the discharge option is $6.6 MM.
The incremental new source compliance cost for the discharge option
is $-0.57 MM/year, or a savings of $570,000.
For existing sources, the costs under the zero discharge option
(total annual = $7.0 MM/year) are the costs that Gulf of Mexico
baseline SBF wells incur moving from discharge to zero discharge. For
new sources, the incremental cost for the zero discharge option is $1.6
MM/year.
As a sensitivity analysis, EPA performed two additional discharge
option compliance cost analyses by varying the fraction of current Gulf
of Mexico shallow water OBF wells that would convert to SBF after the
rule. In the analysis presented above, EPA used an estimate of 20
percent, based on information provided by industry sources. Due to the
uncertainty of predicting future industry activity, the Agency
investigated the range of discharge option compliance costs that would
result assuming that either zero percent of the OBF wells would convert
to SBF use (maintain at 113 SBF wells) or 100 percent of the OBF wells
would convert to SBF use (increase to 225 SBF wells). The ``zero
percent convert'' analysis resulted in an annual incremental cost
savings of $5.6 MM industry wide, and the ``100 percent convert''
analysis resulted in an annual incremental savings of $10.2 MM. The
[[Page 5520]]
savings for the ``20 percent convert'' analysis falls between these
values, at $6.6 MM (see Table IX-2). Thus, regardless of the number of
wells assumed to convert from OBF to SBF, the discharge option results
in industry-wide incremental cost savings.
D. Method for Estimating Pollutant Reductions
The methodology for estimating pollutant loadings and incremental
pollutant reductions effectively parallels that of the compliance cost
analyses. The pollutant reduction analyses are based on the size and
number of the four model wells identified in Table IX-1, as well as
pollutant characteristics of the cuttings wastestream compiled from
previous rulemaking efforts and from industry sources.
For wells that currently use SBFs and discharge SBF-cuttings in the
Gulf of Mexico, EPA projects that the discharge option of this rule
will decrease the discharges of SBFs by over 15.4 MM pounds annually
due to the retention limit. However, EPA projects that certain OBF
wells will convert to SBF wells, and these SBF wells would discharge
3.6 M pounds of SBFs annually. Therefore, EPA calculated that including
this increased number of SBF wells, the discharge of SBF would be
reduced just 11.8 MM pounds annually. Specifically, EPA projects that
all OBF wells in offshore California and Cook Inlet, Alaska, and 20
percent, or 23 wells, of the OBF wells in the Gulf of Mexico, will
convert to SBF. Also because of this conversion from OBF wells to SBF
wells, EPA projects an increase in the annual discharge of dry drill
cuttings of 25.9 MM pounds. With dry drill cuttings discharges
increasing 25.9 MM pounds and SBF discharges decreasing 11.8 MM pounds,
EPA projects that the discharge option of this rule would lead to an
overall increase in discharges of 14.1 MM pounds annually.
Table IX-4 lists the total annual baseline pollutant loadings,
compliance pollutant loadings, and incremental pollutant reductions
calculated for existing and new sources.
Table IX-4.--Summary Annual Pollutant Loadings and Incremental Reductions for Existing and New Sources
[Lbs/year] \1\
----------------------------------------------------------------------------------------------------------------
Offshore Cook Inlet,
Gulf of Mexico California Alaska Total
----------------------------------------------------------------------------------------------------------------
Baseline Technology Loadings:
Discharge with 11% retention of base
fluid on cuttings.................. 177,390,660 0 0 177,390,660
Zero Discharge (current OBF-drilled
wells only)........................ 0 0 0 0
Compliance Option Loadings:
Discharge with 7% retention of base
fluid on cuttings.................. 180,527,712 10,420,876 590,550 191,539,138
Zero Discharge via land disposal or
on-site injection.................. 0 0 0 0
Incremental Pollutant Loadings
(Reductions):
Discharge with 7% retention of base
fluid on cuttings.................. 3,137,028 10,420,876 590,550 \1\ 14,148,454
Zero Discharge via land disposal or
on-site injection.................. (177,390,660) 0 0 (177,390,660)
----------------------------------------------------------------------------------------------------------------
\1\ Consists of 11.8 MM pounds decreased discharge of SBF, 17,366 pounds decreased discharge of formation oil,
and 25.9 MM pounds increased discharge of drill cuttings.
In order to act as a summary, the values in Table IX-4 above
combine the effects of both existing and new sources. The values for
existing sources alone may be determined by subtracting the
corresponding values for new sources that are presented in Table IX-5.
In the calculation of per-well pollutant loadings and incremental
pollutant reductions, a list of pollutant characteristics was developed
in the same manner as the pollutant reduction analyses performed in the
Coastal Oil and Gas Rulemaking effort (EPA, 1996). The pollutant list
consists of conventional, priority, and non-conventional pollutants.
Conventional pollutants include total suspended solids (TSS) and oil
and grease. The TSS derives from two sources: the drill cuttings and
the barite in the adhering drilling fluid. The drilling fluid is
assumed to contain an average 33 percent (by weight) barite and 47
percent (by weight) synthetic base fluid (drilling fluid formulation
data were calculated from data provided in the 1997 API report by
Annis). Metals, both priority and non-conventional, derive from the
barite in the adhering drilling fluid. In the Offshore Oil and Gas
Rulemaking, EPA concluded that barite is the primary source of metals
in drilling fluid (EPA, 1993). The metal concentrations from the
Offshore analysis were adopted for this analysis. In terms of loadings
the synthetic base fluid adhering to the cuttings, plus an assumed 0.2
percent (by volume) of formation oil contamination, are considered oil
and grease. EPA recognizes, however, that there are nonconventional
components of the SBF base fluids and formation oil. The 0.2 percent
(vol.) of formation oil in the wastestream is assumed because EPA
believes that this concentration would occasionally be found in
drilling fluids, and would meet the effluent limitation in today's
proposal. The organic pollutants, both priority and non-conventional,
derive from the formation oil contamination. The specific organic
pollutant concentrations were obtained from analytical data presented
in the Offshore Oil and Gas Development Document for Gulf of Mexico
diesel (EPA, 1993). The SBF base fluids are considered non-conventional
pollutants.
In the discharge option, for each model well two sets of
calculations were developed, based on 11 percent and 7 percent
retention, to determine the per-well volumes of synthetic base fluid,
water, barite, dry cuttings and formation oil in the wastestream. The
calculations were based upon the assumed drilling fluid formulation of
47% (wt.) synthetic base fluid, 20% (wt.) water, and 33% (wt.) solids
as barite, the retention values, and the 0.2% (vol.) formation oil
contamination. Details of these calculations are presented in the
Development Document.
The waste volume estimates resulting from the above calculations
were applied to the pollutant concentrations to determine the per-well
pollutant loadings and incremental pollutant reductions. As in the
compliance cost analysis, the per-well values were then multiplied by
the numbers of wells in each option and each geographic area (see Table
IX-1) to determine the total industry-wide pollutant loadings and
reductions. For baseline SBF wells that discharge, baseline pollutant
loadings were calculated at 11 percent retention, according to
information gathered by
[[Page 5521]]
the industry using currently available technology. EPA calculated the
incremental pollutant reduction as these wells move to the discharge
option at an average SBF base fluid retention on cuttings of 7 percent.
For baseline OBF wells that do not discharge, the baseline loadings
are zero. As baseline wells that do not discharge move to the discharge
option, EPA calculated a loading increase at seven percent retention.
This occurs for wells in offshore California, coastal Cook Inlet, and a
fraction of OBF wells in the Gulf of Mexico that EPA assumes will
convert to SBF subsequent to this rulemaking.
EPA projected that balancing the reductions in per-platform
discharge due to the retention limit with the increased number of
platforms discharging SBF-cuttings leads, annually, to the decrease in
discharge of SBFs of 11.8 MM pounds, the decrease in formation oil
discharge of 17,366 pounds, and the increase in drill cuttings
discharge of 25.9 MM pounds. This yields a net increase of 14.1 MM
pounds discharged annually in the discharge option.
The incremental pollutant reduction for the zero discharge option
is elimination of the baseline loading of currently discharging wells
at 11 percent retention. Table IX-4 shows the annual incremental
pollutant reduction for the zero discharge option is 159 MM pounds.
As stated in section IX.C.4, EPA investigated the range of
incremental compliance costs and pollutant reductions assuming that, in
the discharge option, either zero percent or 100 percent of current OBF
wells in the GOM would convert to SBF. EPA further assumed that all OBF
wells in the GOM are in the shallow water. The analysis above is based
on 20 percent of the OBF wells converting to SBF. The ``zero percent
convert'' analysis resulted in an annual incremental pollutant
reduction of 3 MM pounds industry wide, and the ``100 percent convert''
analysis resulted in an annual increase of discharges of 89.0 MM pounds
per year. The increased discharges for the ``20 percent convert''
analysis falls between these values, at 15.8 MM pounds (see Table IX-
4). In the 100 percent convert scenario, the 89 MM pounds consists of
76 MM pounds of dry cuttings and 13 MM pounds of associated SBFs.
The method of estimating pollutant loadings and reductions for new
sources is the same as that for existing sources. As discussed in
section IX.C.5, EPA estimated that 19 new source wells are located in
the Gulf of Mexico, including one in the shallow water and 18 in the
deep water (see also Table IX-1). For new sources, no OBF wells are in
the baseline, because new sources would be projected to occur mainly in
deep water, where operators generally prefer to use SBFs for cost,
performance, and to minimize liability. In the new source analysis,
there are pollutant discharge reductions for both the discharge option
and the zero discharge option because all new source wells move from a
baseline of discharge at an average 11 percent retention of synthetic
base fluid on cuttings to discharge at seven percent retention under
the discharge option or to zero discharge under the zero discharge
option. The total annual NSPS incremental pollutant reductions are 1.6
MM pounds for the discharge option and 18.3 MM pounds for the zero
discharge option. The discharge option reduction consists of 1.6 MM
pounds of SBF, and a small amount (2,800 pounds) of formation oil.
Table IX-5.--Summary Annual Pollutant Loadings and Incremental Reductions for Management of SBF Cuttings From
New Sources
[Lbs/year]
----------------------------------------------------------------------------------------------------------------
Loadings/
Technology basis reductions
----------------------------------------------------------------------------------------------------------------
Baseline Loadings....................... Discharge with 11% retention of base fluid on 18,286,914
cuttings.
NSPS Pollutant Loadings................. Discharge with 7% retention of base fluid on 16,676,538
cuttings.
Zero Discharge via land disposal or on-site 0
injection.
Incremental NSPS Pollutant Reductions... Discharge with 7% retention of base fluid on 1,610,394
cuttings.
Zero Discharge via land disposal or on-site 18,286,914
injection.
----------------------------------------------------------------------------------------------------------------
E. BCT Cost Test
The BCT cost test, described in section VI.E of today's notice, was
not performed for either of the regulatory options investigated for
this rulemaking. The BCT cost test evaluates the reasonableness of BCT
candidate technologies as measured from BPT level compliance costs and
pollutant reductions. In today's rulemaking, the proposed BCT level of
regulatory control is equivalent to the BPT level of control for both
the preferred discharge option 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.
X. Economic Analysis
A. Introduction and Profile of the Affected Industry
This section presents EPA's estimates of the economic impacts that
would occur under the regulatory options proposed here. The results of
this analysis are described in more detail in the Economic Analysis of
Proposed 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-98-020).
Under the preferred discharge option, the proposed effluent
guidelines would provide a cost savings to industry. This cost savings
would be experienced by wells currently discharging cuttings
contaminated with SBFs and by wells currently using OBF and switching
to SBF as a result of this rule. As discussed in Section IX, the cost
savings for current SBF dischargers result from the use of improved
solids control equipment, allowing operators to recycle additional
volumes of expensive SBFs, which more than offsets the costs of the
improved solids control equipment. For wells that would have been
drilled with OBF, the cost savings result from switching to SBF and
discharging, thus avoiding higher disposal costs of zero discharge.
Operations using and discharging WBFs would not incur costs or realize
costs savings under this rule because EPA does not expect operators to
convert from WBFs to SBFs, as discussed above. This section of today's
notice describes the segment of the oil and gas industry that would
benefit from this rule (i.e.,
[[Page 5522]]
the number of firms and number of wells per year that would incur costs
or realize savings under the proposed rule), the financial condition of
the potentially affected firms, the aggregate cost savings to that
segment, and any impacts that might arise as a result of the rule. The
Agency also discusses impacts on small entities, presents a cost-
benefit analysis, and discusses cost-effectiveness. EPA also evaluated
a zero-discharge option, which was considered but not selected for
proposal, and found it would have a minor impact on a few entities
(large and small) operating in the affected offshore and coastal
regions. This discussion will form the basis for EPA's findings on
regulatory flexibility, presented in Section XI.B.
For this profile, EPA is relying on information developed by
Minerals Management Service (MMS) for EPA. This information includes
wells drilled in federal waters during 1995, 1996, and 1997, along with
the MMS-assigned numbers identifying the operators. These data were
summarized by MMS from MMS's Technical Information Management System.
MMS grouped wells by location (Pacific and Gulf drilling operations
were tallied separately), water depth (up to 999 ft and 1,000 ft or
more), and by type (exploratory or development). MMS also provided a
list of operators by operator number. EPA linked the name of the
operators to wells drilled using the operator number. Names of all
operators who had drilled any well in any of the three years were then
compiled. EPA used the Security and Exchange Commission's (SEC's) Edgar
database, which provides access to various filings by publicly held
firms, such as 8Ks and 10Ks. The former documents are useful for
determining mergers and acquisitions in more detail, and 10Ks provide
annual balance sheet and income statements, as well as listing
corporate subsidiaries. The information in the Edgar database was used
to identify parent companies or recent changes of ownership. EPA also
used a database maintained by Dun & Bradstreet (D&B), which provides
estimates of employment and revenue for many privately held firms, and
financial data compiled by Oil and Gas Journal on publicly held firms.
Other sources of data used in the economic analysis include the
Development Document for this proposed rule; EPA, 1993, Economic Impact
Analysis of Final Effluent Limitations Guidelines and Standards of
Performance for the Offshore Oil and Gas Industry (EPA 821/R-93-004);
and EPA, 1995, Economic Impact Analysis of Final Effluent Limitations
Guidelines and Standards for the Coastal Subcategory of the Oil and Gas
Extraction Point Source Category (EPA 821/R95-013).
For profiling purposes in all regions, EPA divided the potentially
affected firms identified using the MMS, SEC, and D&B data into two
basic categories. The first category consists of the major integrated
oil companies, which are characterized by a high degree of vertical
integration (i.e., their activities encompass both ``upstream''
activities--oil exploration, development, and production--and
``downstream'' activities--transportation, refining, and marketing).
The second category of affected firms consists of independents engaged
primarily in exploration, development, and production of oil and gas
and not typically involved in downstream activities. Some independents
are strictly producers of oil and gas, while others maintain some
service operations, such as contract drilling and well servicing. EPA
used the U.S.A. Oil Industry Directory, 37th Edition, 1998, published
by PennWell Publishing Co., Houston, Texas, to identify firms as
majors, independents, or foreign-owned.
The two types of oil and gas firms, majors and independents, are
very different types of entities, in most cases. The major integrated
oil companies are generally larger than the independents, and are often
among the largest corporations in the world. As a group, the majors
typically produce more oil and gas, earn significantly more revenue and
income, and have considerably more assets and greater financial
resources than most independents. Furthermore, majors tend to be
relatively homogeneous in terms of size and corporate structure. Majors
do not meet the definition of small firm under the Regulatory
Flexibility Act (RFA). Most majors are C corporations (i.e., the
corporation pays income taxes).
Independents vary greatly by size and corporate structure. Larger
independents tend to be C corporations; small firms might also pay
corporate taxes, but they also can be organized as S corporations
(which elect to be taxed at the shareholder level rather than the
corporate level under subchapter S of the Internal Revenue Code). Small
firms also might be organized as limited partnerships, or sole
proprietorships, whose owners, not the firms, pay taxes.
2. Profile of the Potentially Affected Oil and Gas Regions
a. Gulf of Mexico.--As discussed in Sections IV and IX of this
notice, the Gulf of Mexico beyond 3 miles from shore is the most active
of the four oil and gas regions concerning this proposed rule. Nearly
all exploration and development activities in the Gulf are taking place
in the Western Gulf of Mexico, that is, the regions off the Texas and
Louisiana shores. Very little drilling is occurring off Mississippi,
Alabama, and Florida. The Western Gulf Region also is associated with
the majority of the current use and discharge of SBF cuttings.
As stated above, the rule would apply only where WBFs and
associated drill cuttings may be discharged, i.e., 3 miles or more from
shore. Using the MMS, SEC, and D&B data discussed above, EPA accounted
for the various corporate relationships and transactions to determine
the total number of firms actively drilling in the affected regions of
the Gulf. EPA counted 96 potentially affected firms at the parent
company level in the Gulf of Mexico, of which 15 are considered majors.
Twelve of the 96 firms are identified as foreign-owned (not including
U.S. majors such as Shell Oil, which is affiliated with Royal Dutch/
Shell Group), and these firms are included in the analysis. Non-foreign
independents are estimated to total 69 firms.
Financially, the potentially affected operators are a healthy group
of firms. Among publicly held firms, median return on assets for the
group is 4.3 percent, median return on equity is 10.2 percent, and
median profit margin (net income/revenues) is 6.6 percent, according to
1997 financial data. Among these publicly held firms, 60 out of 69
firms, or 87 percent, reported positive net income for 1997.
As discussed above in Section IX, EPA estimates that an average of
1,127 wells are drilled each year in the Gulf of Mexico, of which 1,108
are considered to be existing wells and 19 are considered to be new
sources. EPA estimates (see Section IX) that each year 113 wells are
drilled using SBFs and 112 are drilled using OBFs for at least a
portion of the drilling operation. Of the 112 wells drilled with OBFs,
EPA estimates that 20 percent, or 23 wells, would convert from OBF to
SBF as a result of this rule. These wells are all assumed to be located
in shallow water (see Table IX-1 in Section IX). The remaining 902
wells that are drilled annually in the Gulf of Mexico are assumed to be
drilled exclusively using WBFs and would not incur costs or realize
savings under the proposed rule.
b. Offshore California.--Most production activity in the Offshore
California region is occurring in an area 3 to 10 miles from shore off
of Santa Barbara and Long Beach, California. There are five operators
actively drilling
[[Page 5523]]
(1995-1997) in the California Offshore Continental Shelf (OCS) region.
These operators are Chevron; Aera Energy, LLC; Exxon; Torch Energy
Advisors; and Nuevo Energy Co. Detailed information on Torch Energy
Advisors (other than employment and revenues) and Aera Energy is not
available. Among the remaining firms, median return on assets is 9.0
percent, median return on equity is 18.6 percent, and median profit
margin is 5.7 percent. No operators reported negative net income among
publicly held firms. Thus, the California firms, like the Gulf firms,
generally appear to be financially healthy.
As discussed in Section IX, EPA estimates that an average of 26
development wells and no exploratory wells are drilled in the
California OCS each year. EPA further estimates that no wells are
currently drilled using SBFs and 12 wells are drilled each year using
OBFs. EPA assumes that all 12 of these OBF wells convert to SBF as a
result of this rule. All wells are considered existing sources. EPA
assumes the remaining 14 wells are drilled exclusively using WBFs and
are thus would not incur costs or realize savings under this proposed
rule (see Table IX-1 in Section IX).
c. Cook Inlet, Alaska.--Cook Inlet, Alaska, is divided into two
regions, Upper Cook Inlet, which is in state waters and is governed by
the Coastal Oil and Gas Effluent Guidelines, and Lower Cook Inlet,
which is considered Federal OCS waters and is governed by the Offshore
Oil and Gas Effluent Guidelines. Lower Cook Inlet is discussed as part
of the Alaska Offshore region in Section X.A.2.d below. All references
to Cook Inlet mean Upper Cook Inlet unless otherwise identified.
Three operators are currently active in Cook Inlet: Unocal,
Phillips, and Shell (as Shell Western). All three are major integrated
oil firms, and all three also operate in the Gulf of Mexico. In
addition, ARCO also has been involved in exploratory drilling in the
Sunfish Field, but Alaska state data indicate that Phillips bought
ARCO's interests in this field and will pursue any drilling from its
Tyonek platform. Median return on assets for this group is 7.1 percent,
median return on equity is 14.1 percent, and median profit margin is
7.3 percent. No firm reported negative net income in 1997. Again, these
firms appear financially healthy.
Over the past three years (1995-1997) operators have drilled an
average of about 7 wells per year (see Table IX-2 in Section IX). EPA
estimates that no off-platform drilling will be undertaken in Cook
Inlet. Thus for the purpose of estimating impacts for today's proposal,
EPA assumes seven wells per year will be drilled in Cook Inlet, and all
are considered existing sources. No operators currently use SBFs in
Cook Inlet. Of the seven wells drilled in Cook Inlet, EPA estimates
that one well per year might be drilled annually using OBFs, and as a
result of this rule, this OBF well would convert to SBF.
d. Offshore Alaska. The offshore Alaska region comprises several
areas, which are located both in state waters and in federal OCS areas.
The most active area for exploration has been the Beaufort Sea, the
northernmost offshore area on the Alaska coastline. Other areas where
some exploration has occurred include Chukchi Sea to the northwest,
Norton Sound to the West, Navarin Basin to the west, St. George Basin
to the southwest, Lower Cook Inlet to the south, and Gulf of Alaska,
along the Alaska panhandle. The only commercial production is occurring
in the Beaufort Sea region.
To EPA's knowledge, no operations are discharging any drilling
fluids or cuttings in the offshore Alaska region. No discharge is
occurring in state waters due to state law requiring operators to meet
zero discharge. In the federal offshore region, the Offshore Guidelines
do not specifically prohibit discharge of SBF cuttings, but all
operators historically have injected their drilling wastes. No
commercial production has occurred in any federal offshore area. Some
promising finds have been made in federal offshore waters in recent
years, but development may be several years off. These fields include
the Liberty (Tern Island) Field and the Northstar Field, both in the
Beaufort Sea. Currently a draft Environmental Impact Statement (EIS) is
being prepared for the Liberty Field. The Northstar Field has
encountered significant resistance to development. The operator (BP)
halted construction for over one year as a result of a recently
resolved lawsuit and has just begun the task of preparing a final
environmental impact statement, which must be finalized before any
production operations can proceed.
Since the beginning of exploration in the Alaska Offshore region,
82 exploratory wells have been drilled in Federal Offshore waters,
primarily in the Beaufort Sea, where nearly 40 percent of all
exploratory wells in the Alaska federal offshore region have been
drilled. Exploratory well drilling in federal waters has slacked off
significantly in recent years. From a peak of about 20 wells per year
in 1985, no wells were drilled in 1994, 1995, and 1996, and two were
drilled in 1997, for an average of less than one well drilled per year.
EPA assumes that no significant drilling activity will be occurring in
the Federal Offshore regions of Alaska. Offshore Alaska, therefore, is
within the scope of the regulation but is not expected to be associated
with costs or savings as a result of the proposed effluent guidelines,
either in state offshore waters (because of state law) or in federal
waters (due to historic practice and lack of drilling activity). Wells
drilled in this region are not included in the count of potentially
affected wells.
3. Summary of Well Counts and Operators
EPA estimates that a total of 1,160 wells, on average, are drilled
each year in the regions potentially affected by the SBF Guidelines. Of
these, EPA estimates that 113 wells are drilled, on average, each year
using SBFs in the Gulf (none in California and none in Cook Inlet). EPA
further estimates that a total of 125 wells are drilled annually using
OBFs, of which 112 are drilled in the Gulf, 12 in California, and 1 in
Cook Inlet. EPA estimates that the remaining 922 wells drilled annually
in the affected regions are drilled exclusively with WBFs and would not
incur costs or realize savings under the proposed rule. EPA assumes
that a total of 23 wells in shallow water locations, 12 wells in
California, and 1 well in Cook Inlet, for a total of 36 wells, would
switch from OBFs to SBFs if the SBF effluent guidelines allow
discharge.
The number of operators currently drilling wells in the regions
total 99 firms. These operators include the 96 operators in the Gulf of
Mexico and 3 additional operators in the Pacific (2 Pacific operators
also drill in the Gulf). All Cook Inlet operators also drill in the
Gulf. These counts will be used as baseline data for the economic
analysis.
B. Costs and Costs Savings of the Regulatory Options
EPA considered two options for the proposed rule for both BAT and
NSPS, a discharge option and a zero discharge option. Table X-1
summarizes the costs and costs savings of each alternative considered
in this rule under both BAT and NSPS. This information was presented in
more detail in Section IX. For additional information, see Tables IX-2
and IX-3 in Sections IX.C.
[[Page 5524]]
Table X-1.--Costs and Cost Savings of the Regulatory Options
----------------------------------------------------------------------------------------------------------------
Option BAT NSPS Total
----------------------------------------------------------------------------------------------------------------
Discharge.............................................. ($6,586,322) ($569,600) ($7,155,922)
Zero Discharge......................................... $6,963,896 $1,594,418 $8,558,314
----------------------------------------------------------------------------------------------------------------
As Table X-1 shows, the preferred discharge option is associated
with a cost savings of $6.6 million per year for BAT and $0.6 million
per year for NSPS, for a total cost savings of $7.2 million per year.
The cost estimates for the zero discharge option are $7.0 million per
year under BAT and $1.6 million per year under NSPS, for a total of
$8.6 million per year.
C. Impacts from BAT Options
For each regulatory option, EPA estimated the change in the cost of
drilling wells, impacts on operating a production unit (typically a
platform), impacts on firms, both large and small (impacts on small
firms specifically are discussed in Section X.F), employment impacts in
the oil and gas industry, and impacts on related industries (e.g.,
drilling contractors, drilling fluid companies, mud cleaning equipment
rental firms, transport and disposal firms, etc.) as a result of the
proposed BAT requirements. The results of these analyses are summarized
below. EPA concludes that, for the preferred option, nearly all
economic impacts are positive and finds the preferred option to be
economically achievable in the regions analyzed, as well as for any
other region where discharge would be allowed.
1. Impacts on Costs of Drilling Wells
In this section, EPA shows the impacts of the costs associated with
this rule by comparing per-well costs with the total average cost to
drill a well. Table X-2 shows the four model well types defined in
Section IX and provides estimates of potential costs or cost savings as
a percentage of total costs to drill a well associated with various
subsets of these well types. Costs and cost savings vary depending on
the region, the type of fluid currently used, and the operator's choice
of zero discharge (under the zero discharge option only)--hauling to
shore for disposal or injecting the waste (the latter, less expensive
option is not technically feasible at all locations). See the
Development Document for detailed information on how the numbers of
wells were estimated in each category and the Economic Analysis report
for how the aggregate costs of each well type were disaggregated to
estimate a per well cost.
Table X-2.--Cost Savings of the Improved Discharge Option as a Percentage of Baseline Drilling Costs
[$1997]
----------------------------------------------------------------------------------------------------------------
Cost as a percentage
Incremental Incremental Total of total drilling
cost of cost of baseline cost
Type of well Number of discharge zero cost of ---------------------
wells option (per discharge drilling Zero
well) option (per well ($MM) Discharge discharge
well) option option
----------------------------------------------------------------------------------------------------------------
Gulf of Mexico:
Deep Water SBF Developmental (haul). 14 ($29,302) $95,507 $2.9 -1.0 3.3
Deep Water SBF Developmental
(inject)........................... 4 (29,302) 57,205 2.9 -1.0 2.0
Shallow Water SBF Developmental
(haul)............................. 10 (17,502) 19,113 2.9 -0.6 0.7
Shallow Water SBF Developmental
(inject)........................... 2 (17,502) \1\ (10,555
) 2.9 -0.6 -0.4
Shallow Water OBF Developmental
(haul)............................. 12 (36,615) 0 2.9 -1.3 0.0
Shallow Water OBF Developmental
(inject)........................... 3 (6,947) 0 2.9 -0.2 0.0
Deep Water SBF Exploratory (haul)... 46 (70,502) 79,813 3.9 -1.8 2.0
Deep Water SBF Exploratory (inject). 11 (70,502) 127,825 3.9 -1.8 3.3
Shallow Water SBF Exploratory (haul) 6 (41,502) 28,315 4.9 -0.8 0.6
Shallow Water SBF Exploratory
(inject)........................... 1 (41,502) \1\ (21,950
) 4.9 -0.8 -0.4
Shallow Water OBF Exploratory (haul) 6 (69,817) 0 4.9 -1.4 0.0
Shallow Water OBF Exploratory
(inject)........................... 2 (19,552) 0 4.9 -0.4 0.0
California:
Deep Water OBF Developmental........ 11 (43,658) 0 1.6 -2.7 0.0
Shallow Water OBF Developmental..... 1 (28,899) 0 1.6 -1.8 0.0
Alaska:
Shallow Water OBF Developmental..... 1 (92,266) 0 2.8 -3.3 0.0
----------------------------------------------------------------------------------------------------------------
\*\ See Development Document for explanation of cost savings.
Note: Negative values or values in parentheses represent a cost sa
Table X-2 shows that most cost savings under the preferred
discharge option would be about 1 to 2 percent of total well drilling
costs, with a few exceptions. Deep water development wells using OBFs
in California would realize cost savings of as much as 2.7 percent of
total costs, and the estimated one Alaska well using OBFs in Cook Inlet
would realize a cost savings of 3.3 percent of total well drilling
costs. In general, these cost savings are not a large portion of costs
to drill and therefore should act as no incentive to at most a small
incentive on well drilling activity.
Under zero discharge, wells currently using OBFs would incur no
incremental costs of compliance since they already meet zero discharge
requirements. Among those currently using SBFs, the median percentage
of compliance costs to the total cost of drilling wells is 2.0 percent.
EPA believes these results indicate that the rule would be economically
achievable, but has selected the discharge option instead in
[[Page 5525]]
order to mitigate non-water quality environmental impacts; see Section
VI above.
2. Impacts on Platforms and Production
Neither the discharge option nor the zero discharge option would
have a significant impact on production decisions on platforms. As
noted above, cost savings among operations currently using SBFs are a
small fraction of the overall cost to drill a well in the offshore, so
the cost savings associated with the preferred discharge option would
have a small effect on an operator's decisions to drill, although some
small encouragement to drilling may result.
Under EPA's zero discharge option, EPA investigated potential
impacts based on previous work performed as part of the offshore oil
and gas effluent guidelines rule. The costs of such an option, compared
to the baseline costs of drilling wells in the Gulf are presented in
Table X-2. EPA previously investigated the impact of zero discharge of
all drilling fluids and cuttings on platform-based production
operations in the offshore regions of the Gulf and found, at that time,
that ``none of the options considered * * * [including zero discharge]
for drilling fluids and drill cuttings has an adverse impact on
hydrocarbon production.'' (58 FR 12,454-12,152). Furthermore, as stated
in the economic impact analysis prepared for the rule (Economic Impact
Analysis of Final Effluent Limitations Guidelines and Standards of
Performance for the Offshore Oil and Gas Industry, EPA 821/R-93-004),
EPA estimated no change in the total production for any project
analyzed under any regulatory scenario for drilling wastes (including
zero discharge). EPA believes that a similar impact would occur today
and thus zero discharge would be economically achievable.
3. Impacts on Firms
EPA estimated impacts on firms by assessing the costs and cost
savings of the regulatory options as a percentage of revenues. The cost
savings associated with the preferred discharge option would have from
no impact to a very small impact on the investment decisions by the
majority of the firms affected by the proposed rule. EPA assumes that
the likeliest users of SBF in shallow water locations are the same
operators who use SBF in deep water operations. EPA solicits comments
on this assumption. In the Gulf of Mexico, a total of 18 firms (19
percent of the 96 firms considered potentially affected in the Gulf)
drilled in deepwater locations over the period 1995-1997. Total cost
savings among these firms would probably be at most nearly 0.3 percent
of revenues.
Among the 18 firms likely to be using SBFs (the 18 deepwater
drilling firms), costs of zero discharge of SBF cuttings would be at
most 0.4 percent of revenues among these firms. Section X.F discusses
costs for zero discharge as a percent of revenues for each potentially
affected small firm currently drilling with SBFs and discharging
cuttings.
4. Secondary Impacts
a. Employment and Output.--EPA anticipates no negative impacts on
employment and output (revenues) from the preferred option because, in
the aggregate, cost savings are realized. Changes in employment and
output are directly proportional to costs of compliance (that is,
higher costs lead to lower employment and output) thus cost savings
would minimally increase employment and output in the oil and gas
industry, but these gains would be offset by losses elsewhere in the
economy (e.g., waste disposal firms). Under zero discharge, the costs
of compliance would minimally decrease employment and output, but these
decreases would be offset by gains elsewhere in the economy (e.g.,
waste disposal firms).
The gross effects of the preferred option (that is, without
considering losses in other industries that were not quantified) would
total 93 full-time equivalents (FTE) gained in the U.S. economy (1 FTE
= 2,080 hours and can be equated with one full-time job) and $13.9
million in additional output per year throughout the U.S. economy as a
whole. The zero discharge option is estimated to result in a loss
(unadjusted for gains in other industries, which EPA did not quantify)
of 111 FTEs and a loss of $16.6 million in output per year in the U.S.
economy. These losses occur within the oil and gas industry as well as
in other industries. The net effect of the rule (once adjustments for
changes in other industries are accounted for) on the U.S. economy
under either option is likely to be close to zero.
To the extent that any costs savings might be reinvested in
additional drilling or otherwise encourage additional drilling,
employment and output could increase in the oil and gas industry by
more than that associated with the cost savings alone. EPA has not
quantified this potentially positive, albeit very small, effect.
b. Secondary Impacts on Associated Industries.--EPA qualitatively
analyzed the secondary impacts on associated industries from the
preferred option. Impacts on drilling contractors should be neutral to
positive, with some increase in employment in these firms occurring if
they reinvest the cost savings. Impacts on firms supplying drilling
fluids should be neutral to positive, since most firms supplying
drilling fluids stock both OBFs and SBFs. To the extent that SBFs have,
at a minimum, the same profit margin as OBFs, there would be little to
no impacts on these firms, because SBFs would replace OBFs in some
instances under the preferred discharge option. If drilling increases
as a result of reinvestment, some positive impacts might occur.
Firms that provide rental of solids separation systems presumably
would purchase and provide improved solids separation systems once
demand for these systems developed with the promulgation of the rule.
Because these more efficient systems would most likely be rented in
addition to, rather than in place of, less efficient systems, impacts
on these firms would be positive.
Firms that manufacture the improved solids separation equipment and
firms that manufacture equipment or provide services needed to comply
with the new testing requirements would prosper.
The firms providing transport and landfilling or injection of OBF-
contaminated cuttings would sustain economic losses as a result of the
rule. Under the preferred option, for wells currently using OBFs, EPA
estimates that waste generated for disposal by landfill and injection
would be reduced by 34 million pounds per year (see Section VII.E and
Section X.E). Under a zero discharge option, these firms would
experience potential economic gains, because more waste (178 million
pounds per year) would be generated for land disposal or injection than
is currently generated (see Section VII.E and Section X.E).
c. Other Secondary Impacts.--There would be no measurable impacts
on the balance of trade or inflation as the result of this proposed
rule. EPA projects insignificant impacts on domestic drilling and
production, and therefore insignificant impacts on the U.S. demand for
imported oil. Additionally, even if there were costs associated with
this rule, the industry has no ability to pass on costs to consumers as
price takers in the world oil market, and thus this rule would have no
impact on inflation.
D. Impacts From NSPS Options
The proposed NSPS option is the same discharge option proposed for
BAT. Under the definitions of new
[[Page 5526]]
source in the Offshore Oil and Gas Effluent Guidelines, an oil and gas
operation is considered a new source only when significant site
preparation work and other criteria are met (see 40 CFR Part 435.11).
Individual exploratory wells, wells drilled from existing platforms and
wells drilled and connected to an existing separation/treatment
facility without substantial construction of additional infrastructure
are not new sources.
As discussed above, the lack of negative economic impacts from
allowing SBF discharge leads EPA to the conclusion that the effluent
guidelines are economically achievable for both existing and new
sources. Additionally, on a per-well basis, NSPS is expected to result
in greater cost savings than BAT because new platforms do not require
the retrofit costs to enable the improved solids control equipment to
be placed on existing platforms. Because the preferred NSPS option
results in cost savings and those cost savings are greater than those
realized by existing operations, there are no barriers to entry. In
fact, the rule might act as an small incentive to new source
development (see discussion in Section X.C.4).
E. Cost-Benefit Analysis
Pursuant to E.O. 12866, EPA chose to quantitatively and
qualitatively compares the costs and benefits of the preferred
discharge option. The total annual cost savings of the rule in pretax
dollars are $7.2 million, including the costs to both existing and new
operations. Benefits also include 72.03 tons of air emissions reduced
from both existing and new sources per year (including nitrogen oxides
and sulfur dioxides, and other ozone precursors). These reductions
arise because operators are encouraged to use SBFs and discharge
cuttings rather than use OBFs and transport wastes to shore for
disposal or grind and inject cuttings). SBF use also results in an
energy savings of 2,302 barrels of oil equivalent per year when the
cuttings are no longer hauled to shore for disposal or ground up for
injection. An additional 14.1 million pounds per year of pollutants,
however, would be discharged to surface waters annually, but due to
pollution prevention technology, this discharge prevents 34 million
pounds of wastes from being land disposed or injected each year. See
Table X-3 for a summary of the costs and benefits of BAT and NSPS
requirements under the discharge option.
Under the zero discharge option, costs would be $8.6 million, and
178 million pounds per year of pollutants would no longer be
discharged, but an additional 34 million pounds of waste would be land
disposed or injected each year. Furthermore, compared to current
practice, 380 tons of air emissions would be generated annually, and
energy consumption would increase by 27,000 barrels of oil equivalent
per year. See Table X-3 for a summary of the costs and benefits of BAT
and NSPS requirements under the zero discharge option. Note that these
costs and benefits are incremental to the current baseline, not
incremental to the discharge option, which is how many of these numbers
are presented in the text in Section VII.
Table X-3.--Summary of Costs and Benefits Under the Discharge Option and Zero Discharge Option
----------------------------------------------------------------------------------------------------------------
Discharge option Zero discharge option
Cost or benefit category -----------------------------------------------------------------
BAT NSPS Total BAT NSPS Total
----------------------------------------------------------------------------------------------------------------
Cost ($million) \1\........................... -$6.6 -$0.6 -$7.2 +$7.0 +$1.6 +$8.6
Energy (barrels of oil equivalent) \2\........ -2,613 +311 -2,302 +24,125 +2,932 +27,057
Solid Waste (MM lbs) \3\...................... -34 0 -34 +165 +13 +178
Air Emissions (tons per year) \2\............. -73.3 +1.28 -72.02 +338.55 +41 +379.55
Water Pollutants (MM lb/yr) \4\............... +15.8 -1.6 +14.1 -159.1 -18.3 -177.4
----------------------------------------------------------------------------------------------------------------
Note: minus signs indicate a cost savings or benefit; plus signs indicate a cost or an impact.
\1\ See Table X-1.
\2\ See Tables VII-1 and VII-2.
\3\ See Section VII.E.
\4\ See Tables IX-4 and IX-5.
F. Small Business Analysis
Pursuant to the requirements of the Regulatory Flexibility Act
(RFA) as amended by the Small Business Regulatory Enforcement Fairness
Act (SBREFA), EPA performed a small business analysis to determine if
an Initial Regulatory Flexibility Analysis (IRFA) must be performed.
The analysis undertaken here is used to determine if the rule would
have a significant impact on a substantial number of small entities.
This section discusses the number of small entities estimated to be
affected by the rule and analyzes the potential magnitude of impact on
these entities. Under the preferred option, no wells are expected to
incur costs, thus no firms are affected in any negative way by the
proposed effluent guidelines. These results will be discussed as they
apply to the RFA and SBREFA requirements in Section XI.B of today's
notice.
Although well drilling and platform operations have not changed
significantly in the intervening years since the offshore rule was
promulgated, many of the operators have changed. When the offshore rule
was promulgated, EPA believed no small firms were likely to be affected
by that rule. As the offshore region of the Gulf, in particular, has
matured, smaller firms have begun drilling and producing. In EPA's
experience (see Economic Impact Analysis for Final Effluent Limitations
Guidelines and Standards for the Coastal Subcategory of the Oil and Gas
Extraction Point Source Category, EPA 821/R95-13), as an oil and gas
region matures the majors can no longer earn returns meeting their
requirements and sell their operations to other firms, usually smaller
independents who have lower overheads, more limited access to capital,
and fewer means and opportunity to take on higher risk or overseas
activities. Because of this change in the size of firms operating in
the offshore region, EPA re-evaluated the earlier conclusion about
small firms operating in offshore regions and estimated impacts on
small business.
The first step of this analysis was to separate the actively
drilling firms into small and large firms. The Small Business
Administration (SBA) characterizes an oil and gas production operator
as small if it employs fewer than 500 employees and an oil and gas
services provider as small if it generates less than $5 million per
year in revenues. Because many small firms in this industry are partly
or wholly owned by larger firms, EPA traced ownership of
[[Page 5527]]
small firms to determine whether their parent companies also were small
businesses. Generally, EPA characterized a firm at the higher level of
organization if it was majority owned by the larger entity (except in a
few instances when the subsidiary was a large business and publicly
available information was available for that level of the corporation;
e.g., Vastar, which is about 80 percent owned by ARCO). This approach
is consistent with SBA's definition of affiliation. Small firms that
are affiliated (e.g., 51 percent owned) by firms not defined as small
by SBA's standards (13 CFR Part 121) are not considered small for the
purposes of regulatory flexibility analysis.
EPA determined that a total of 42 small firms might be subject to
the requirements of the SBF Effluent Guidelines. These 42 small firms,
although meeting SBA's definition of small for this industry, are
generally larger than firms typically considered small in other
industries. The median assets for this group (among publicly held
firms) is about $263 million, median equity is about $127 million,
median revenues are about $16 million, and median net income is about
$2.8 million. Median return on assets is about 1.5 percent, median
return on equity is about 3.3 percent, and net income to revenues (net
profit margin) is about 6.8 percent. Although returns are not as strong
as those associated with the affected industry as a whole, profit
margin is generally about the same as typical margins for the affected
industry, regardless of size of firm. Revenues range from a high of
$383 million to a low of $160,000. Actual or Dun & Bradstreet estimated
revenue figures were identified for nearly all small firms, although
other financial information was available for only about half of the
small firms. Employment at these small firms ranges from a high of 400
to a low of 2. Median employment is approximately 38 persons.
As noted above, under the discharge option, no wells are expected
to incur costs, thus no firms would be affected in any negative way by
the proposed effluent guidelines.
EPA also looked at the impacts of the zero-discharge option, or
other options that would incur costs, in which case those small firms
using SBFs potentially would incur compliance costs. As in the analysis
of all firms discussed above in Section X.C.3, EPA has determined that
the likeliest users of SBF in shallow water locations would be the same
operators who use SBF in deep water operations. Thus the firms with
both deep water and shallow water operations would be the potentially
affected firms. Only one firm meets this definition as well as the SBA
definition of small entity and thus would be an affected small firm
under the zero discharge option. EPA finds that one firm is not a
substantial number of small entities. Further, EPA estimated costs for
zero discharge on this firm and compared these costs to the firm's
revenues. The costs would be less than one percent of revenues under
the zero discharge option, and EPA finds this is not a significant
impact.
G. Cost-Effectiveness Analysis
Cost-effectiveness analysis evaluates the relative efficiency of
options in removing toxic pollutants and nonconventional pollutants.
Cost-effectiveness results are expressed in terms of the incremental
and average costs per pound-equivalent removed. A pound equivalent is a
measure that addresses differences in the toxicity of pollutants
removed. Total pound-equivalents are derived by taking the number of
pounds of a pollutant removed and multiplying this number by a toxic
weighting factor. EPA calculates the toxic weighting factor using
ambient water quality criteria and toxicity values. The toxic weighting
factors are then standardized by relating them to a particular
pollutant, in this case copper.
For the purpose of evaluating most effluent guidelines, EPA's
standard procedure is to rank the options considered for each
subcategory in order of increasing pounds-equivalent removed. The
Agency calculates incremental cost-effectiveness as the ratio of the
incremental annual costs to the incremental pounds-equivalent removed
under each option, compared to the previous (less effective) option.
Average cost-effectiveness is calculated for each option as a ratio of
total costs to total pounds-equivalent removed.
While cost-effectiveness results are usually reported in the Notice
of Proposed Rule for effluent guidelines, those results are not
presented in today's notice because there are no incremental costs
attributed to the proposed option, and EPA did not calculate a cost-
effectiveness ratio for the proposed option. In the rulemaking record,
EPA presents a more detailed discussion of cost-effectiveness analysis
and reports results for the zero discharge option.
XI. Related Acts of Congress, Executive Orders, and Agency
Initiatives
A. Executive Order 12866: OMB Review
Under Executive Order 12866, [58 Federal Register 51,735 (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 proposed rule is not a ``significant regulatory
action,'' and is therefore not subject to OMB review.
B. Regulatory Flexibility Act and the Small Business Regulatory
Enforcement Fairness Act
Under the Regulatory Flexibility Act (RFA), 5 U.S.C. 601 et seq. as
amended by the Small Business Regulatory Enforcement Fairness Act, EPA
generally is required to conduct an initial regulatory flexibility
analysis (IRFA) describing the impact of the proposed rule on small
entities as a part of rulemaking. However, under section 605(b) of the
RFA, if the Administrator certifies that the rule will not have a
significant economic impact on a substantial number of small entities,
EPA has prepared an analysis equivalent to an IRFA.
Using the U.S. Small Business Administration's definition for small
business for this industry (i.e., firms 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), EPA estimates the
proposed rule would apply to 42 small firms. As explained in Sections
IX and X of this notice, none of these small firms are expected to
incur any costs as a result of this rule. Thus, EPA projects no adverse
economic impacts to the small firms. To the contrary, if these firms
use SBF, they are likely to experience cost savings.
Based on the assessment of the economic impact of regulatory
options being considered for the proposed rule
[[Page 5528]]
as discussed in Section X, the Administrator therefore certifies that
the proposed rule would not have a significant economic impact on a
substantial number of small entities. Therefore, the Agency did not
prepare an IRFA.
While EPA has so certified today's proposed rule, the Agency
nonetheless prepared a small business analysis, incorporating many of
the features of the assessment required by the RFA. The small business
analysis for the proposed rule is summarized in Section X.F of this
notice.
C. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Pub.
L. 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under Section 202 of 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. Today's proposed rule contains no Federal
mandates (under the regulatory provisions of Title II of the UMRA) for
State, local, or tribal governments or the private sector. The rule
would impose no enforceable duty on any State, local, or tribal
governments or require any expenditure of $100 million or more to the
private sector. Thus today's proposed rule is not subject to the
requirements of Sections 202 and 205 of the UMRA.
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
intergovernmental mandates, and informing, educating, and advising
small governments on compliance with regulatory requirements. As this
rule has no effect on small governments, this rule would not
significantly or uniquely affect small governments and Section 203 of
the UMRA does not apply.
D. Executive Order 12875: Enhancing Intergovernmental Partnerships
Under Executive Order 12875, EPA may not issue a regulation that is
not required by statute and that creates a mandate upon a State, local
or tribal government, unless the Federal government provides the funds
necessary to pay the direct compliance costs incurred by those
governments, or EPA consults with those governments. If EPA complies by
consulting, Executive Order 12875 requires EPA to provide to the Office
of Management and Budget a description of the extent of EPA's prior
consultation with representatives of affected State, local and tribal
governments, the nature of their concerns, any written communications
from the governments, and a statement supporting the need to issue the
regulation. In addition, Executive Order 12875 requires EPA to develop
an effective process permitting elected officials and other
representatives of State, local and tribal governments ``to provide
meaningful and timely input in the development of regulatory proposals
containing significant unfunded mandates.''
Today's proposed rule would not create a mandate on State, local or
tribal governments. The proposed rule would not impose any enforceable
duties on these entities. Accordingly, the requirements of section 1(a)
of Executive Order 12875 do not apply to this proposed rule.
E. 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 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. As previously discussed this
proposed rule does not impose any mandates on Tribal governments.
Further, the only Indian communities in proximity to the activities
addressed by this proposed rule are in Cook Inlet, Alaska. EPA does not
project, however, that these communities would be affected by this
rule. EPA projects that on average, 8 wells will be drilled in Cook
Inlet annually. EPA further projects that of these 8 wells, one well
would be drilled with OBF in the absence of this rule, and this one OBF
well would convert to using SBF with today's proposed discharge option.
EPA concludes that this effect of one well annually converting from OBF
to SBF is minor, and would not significantly or uniquely affect the
communities of Indian tribal governments. Further, today's proposed
rule would not impose substantial direct compliance costs on such
communities. Accordingly, the requirements of section 3(b) of Executive
Order 13084 do not apply to this rule.
F. Paperwork Reduction Act
The proposed synthetic-based drilling fluids effluent guidelines
contain no new information collection activities and, therefore, no
information collection request will be submitted to OMB for review
under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et
seq.
G. National Technology Transfer and Advancement Act
Under section 12(d) of the National Technology Transfer and
Advancement Act (NTTAA), the Agency is required 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, business practices,
etc.) that are
[[Page 5529]]
developed or adopted by voluntary consensus standards bodies. Where
available and potentially applicable voluntary consensus standards are
not used by EPA, the Act requires the Agency to provide Congress,
through the Office of Management and Budget (OMB), an explanation of
the reasons for not using such standards. The following discussion
summarizes EPA's response to the requirements of the NTTAA.
EPA performed a search of the technical literature to identify any
applicable analytical test methods from industry, academia, voluntary
consensus standard bodies and other parties that could be used to
measure the analytes in today's proposed rulemaking. EPA's search
revealed that there are consensus standards for many of the analytes
specified in the tables at 40 CFR Part 136.3. Even prior to enactment
of the NTTAA, EPA has traditionally included any applicable consensus
test methods in its regulations. Consistent with the requirements of
the CWA, those applicable consensus test methods are incorporated by
reference in the tables at 40 CFR Part 136.3. The consensus test
methods in these tables include American Society for Testing and
Materials (ASTM) and Standard Methods.
Today's proposal would require dischargers to monitor for five
additional parameters with up to six additional methods: polynuclear
aromatic hydrocarbon (PAH) content of the base fluid, biodegradation
rate of the base fluid, sediment toxicity, formation (crude) oil
contamination in drilling fluid (two methods), and quantity of drilling
fluid discharged with cuttings. EPA plans to approve use of test
methods for these parameters in conjunction with the promulgation of
the final rule. In addition, EPA is considering a requirement for
bioaccumulation of the base fluid. EPA has identified applicable
consensus methods for two parameters, ASTM Method E-1367-92 for
sediment toxicity and American Petroleum Institute Retort Method
(Recommended Practice 13B-2) for quantity of drilling fluid discharged
with cuttings. For PAH content of the base fluid, EPA is proposing the
use of EPA Method 1654A which was validated with assistance from a
voluntary consensus standards body. With stakeholder support in data
gathering activities, EPA intends to develop or encourage voluntary
consensus standards bodies to develop appropriate methods for oil
contamination in drilling fluid and biodegradation rate.
H. Executive Order 13045: Children's Health Protection
Executive Order 13045 (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 risk or safety risk that the Agency has reason to believe may
have a disproportionate effect on children. If a 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 proposed rule is not subject to E.O. 13045, ``Protection of
Children from Environmental Health Risks and Safety Risks'' because
this is not an ``economically significant'' regulatory action as
defined by E.O. 12866. Further, EPA interprets E.O. 13045 as applying
only to those regulatory activities that are based on health or safety
risks, such that the analysis required under Section 5-501 of the Order
has the potential to influence the regulation. Thus, this rule is not
subject to E.O. 13045 because it is based on technology performance and
not on health or safety risks.
XII. Regulatory Implementation
A. 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 Parts 122.21, 122.41, 122.44 and 123.25, and for the implementation
of the pretreatment standards under 40 CFR Part 403.10 and 403.12. To
date, EPA has promulgated methods for conventional pollutants, toxic
pollutants, and for some nonconventional pollutants. The five
conventional pollutants are defined at 40 CFR Part 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 Part 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 Part 136.3,
Table I-B. Table I-C at 40 CFR Part 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 Part 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 rulemaking, EPA is proposing to allow use of
analytical methods for determining additional parameters that are
specific to characterizing SBFs and other non-aqueous drilling fluids.
These additional parameters include polynuclear aromatic hydrocarbon
(PAH) content of the base fluid, biodegradation rate of the base fluid,
sediment toxicity, formation (crude) oil contamination in drilling
fluid, and quantity of drilling fluid discharged with cuttings.
EPA worked with stakeholders to identify methods for determining
these parameters. For PAH content, EPA is proposing the use of EPA
Method 1654A. For biodegradation rate, EPA is proposing the use a solid
phase test developed in the United Kingdom. For sediment toxicity, EPA
is proposing the use of American Society for Testing and Material
(ASTM) Method E-1367-92 supplemented with sediment preparation
procedures. For formation (crude) oil contamination in drilling fluid,
EPA is proposing the use of two methods, a reverse phase fluorescence
test and a gas chromatography/mass spectrometry (GC/MS) test. The
reverse phase fluorescence test 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 provides a
definitive identification and quantitation of oil contamination for
baseline analysis. For determining the quantity of drilling fluid
discharged with cuttings, EPA is proposing the use of the American
Petroleum Institute Retort Method (Recommended Pratice 13B-2). EPA
Method 1654A and ASTM E-1367-92 are incorporated by reference into 40
CFR Part 435 because they are published methods that are widely
available to the public. Supplemental sediment preparation procedures
for ASTM E-1367-92 are
[[Page 5530]]
provided in Appendix 3 to 40 CFR Part 435. The text of the four other
proposed methods are provided in Appendices 4-7 to 40 CFR Part 435.
Subpart A.
EPA currently is conducting additional development and validation
of the proposed methods and researching the possible inclusion of
additional or alternate methods. EPA intends to publish a notice of
data availability to solicit comments on the selected methods prior to
publication of a final rule.
On March 28, 1997, EPA proposed a means to streamline the method
development and approval process (62 FR 14975) and on October 6, 1997,
EPA published a notice of intent to implement a performance-based
measurement system (PBMS) in all of its programs to the extent feasible
(62 FR 52098). The Agency is currently determining the specific steps
necessary to implement PBMS in all of its regulatory programs and has
approved a plan for implementation of PBMS in the water programs. Under
PBMS, regulated entities will be able to modify methods without prior
approval and will be able to use new methods without prior EPA approval
provided they notify the regulatory authority to which the data will be
reported. EPA expects a final rule implementing PBMS in the water
programs by the end of calendar year 1998. When the final rule takes
effect, regulated entities will be able to select methods for
monitoring other than those approved at 40 CFR Parts 136 and 435
provided that certain validation requirements are met. Many of the
details were provided at proposal (62 FR 14975) and will be finalized
in the final PBMS rule.
B. Diesel Prohibition for SBF-Cuttings
Under today's proposed rule, drill cuttings that have come in
contact with SBF containing any amount of diesel oil are prohibited
from discharge. A certain amount of formation oil contamination,
however, would be allowed under this proposed rule. Since diesel oil
and formation oil have many components in common, it would be nearly
impossible to analytically determine the absence, or presence, of
diesel when SBFs are contaminated with allowable levels of formation
oil. For this reason, operators are to certify that the SBFs in use are
free of diesel oil if the SBF-cuttings are to be allowed for discharge.
C. Monitoring of Stock Base Fluid
Under today's proposed rule, SBF-cuttings would be allowed for
discharge only if the base fluids used to formulate the SBFs meet
requirements in terms of PAH content, sediment toxicity, and
biodegradation rate. The PAH content should be determined on a
batchwise basis, or production lot basis. This is due to the fact that,
at least for some of the base fluid manufacturing processes, PAH
contamination may occur. Also, the analytical method is rapid and
relatively inexpensive. The sediment toxicity and biodegradation rate
should be determined once per year per base fluid trade name. These are
parameters that EPA does not expect to change on a batch to batch or
lot to lot basis. Also, the methods used to determine the parameters of
sediment toxicity and biodegradation are longer term and more elaborate
tests to conduct.
D. Upset and Bypass Provisions
A recurring issue of concern has been whether industry guidelines
should include provisions authorizing noncompliance with effluent
limitations during periods of ``upsets'' or ``bypasses''. The reader is
referred to the Offshore Guidelines (58 FR 12501) for a discussion on
upset and bypass provisions.
E. Variances and Modifications
Once this regulation is in effect, the effluent limitations must be
applied in all NPDES permits thereafter issued to discharges covered
under this effluent limitations guideline subcategory. Under the CWA
certain variances from BAT and BCT limitations are provided for. A
section 301(n) (Fundamentally Different Factors) variance is applicable
to the BAT and BCT and pretreatment limits in this rule. The reader is
referred to the Offshore Guidelines (58 FR 12502) for a discussion on
the applicability of variances.
F. Best Management Practices
Sections 304(e) and 402 (a) of the Act authorizes the Administrator
to prescribe ``best management practices'' (BMPs). EPA may develop BMPs
that apply to all industrial sites or to a designated industrial
category and may offer guidance to permit authorities in establishing
management practices required by unique circumstances at a given plant.
EPA is considering the use of BMPs as part of the final rule to
address the requirement of zero discharge of SBF not associated with
drill cuttings. EPA understands that there are occasional instances
when spills of SBF occur, and that the location and perhaps even the
timing of these spills is predictable. EPA solicites comments from
industry indicating the types of BMPs that would minimize or prevent
SBF spills. EPA solicites comments from all stakeholders whether the
zero discharge requirement should be controlled in these guidelines
using BMPs or other means, such as a specific limitation.
G. Sediment Toxicity and Biodegradation Comparative Limitations
In lieu of a numerical limitation, between the time of today's
proposal and the final rule, EPA recommends that if SBFs based on
fluids other than internal olefins and vegetable esters are to be
discharged with drill cuttings, data showing the toxicity of the base
fluid should be presented with data, generated in the same series of
tests, showing the toxicity of the internal olefin and the vegetable
ester as standards. Base fluids determined to have LC50
values greater than or equal to the LC50 value determined
for C16-C18 internal olefins, in the same series
of test, would be acceptable for discharge.
For biodegradation testing also, in the interim period between
today's proposed rule and the final rule, EPA recommends that if SBFs
based on fluids other than internal olefins and vegetable esters are to
be discharged with drill cuttings, data showing the biodegradation of
the base fluid should be presented with data, generated in the same
series of tests, showing the biodegradation of the internal olefin as a
standard.
EPA prefers this approach for the sediment and biodegradation
limitations rather than set numeric limitations at this time because of
the small amount of data available to EPA upon which to base these
numerical limits. EPA sees this as an interim solution to provide a
limitation based on the performance of available technologies.
XIII. Solicitation of Data and Comments
EPA encourages public participation in this rulemaking. The Agency
asks that comments address any perceived deficiencies in the record
supporting this proposal and that suggested revisions or corrections be
supported by data. In addition, EPA requests comments on the various
ways of handling the applicability of these proposed guidelines, as
this relates to the definitions for water-based drilling fluids and
non-aqueous drilling fluids.
The Agency invites all parties to coordinate their data collection
activities with EPA to facilitate mutually beneficial and cost-
effective data submissions. Please refer to the ``For Further
Information'' section at the beginning of this preamble for technical
contacts at EPA.
To ensure that EPA can properly respond to comments, the Agency
prefers that commenters cite, where
[[Page 5531]]
possible, the paragraph(s) or sections in the notice or supporting
documents to which each comment refers. Please submit an original and
two copies of your comments and enclosures (including references).
Commenters who want EPA to acknowledge receipt of their comments
should enclose a self-addressed, stamped envelope. No facsimiles
(faxes) will be accepted. Comments and data will also be accepted on
disks in WordPerfect format or ASCII file format.
Comments may also be filed electronically to
``[email protected].'' Electronic comments must be submitted as an
ASCII or Wordperfect file avoiding the use of special characters and
any form of encryption. Electronic comments must be identified by the
docket number W-98-26 and may be filed online at many Federal
Depository Libraries. No confidential business information (CBI) should
be sent via e-mail.
List of Subjects in 40 CFR Part 435
Environmental protection, Non-aqueous drilling fluids, Oil and gas
extraction, Synthetic based drilling fluids, Waste treatment and
disposal, Water non-dispersible drilling fluids, Water pollution
control, Pollution prevention.
Dated: December 29, 1998
Carol M. Browner,
Administrator.
Appendix A To The Preamble--Abbreviations, Acronyms, and Other
Terms Used in This Notice
Act--Clean Water Act
Agency--U.S. Environmental Protection Agency
API--American Petroleum Institute
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
CFR--Code of Federal Regulations
Clean Water Act--Federal Water Pollution Control Act Amendments of
1972 (33 U.S.C. 1251 et seq.)
Conventional pollutants--Constituents of wastewater as determined by
section 304(a)(4) of the Act, including, but no limited to,
pollutants classified as biochemical oxygen demanding, suspended
solids, oil and grease, fecal coliform, and pH
CWA--Clean Water Act
Direct discharger--A facility which discharges or may discharge
pollutants to waters of the United States
D&B--Dun & Bradstreet
DOE--Department of Energy
DWD--Deep-water development model well
DWE--Deep-water exploratory model well
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 percent of the test organisms in a bioassay
mg/l--milligrams per liter MMS--Department of Interior Minerals
Management Service Nonconventional pollutants--Pollutants that have
not been designated as either conventional pollutants or priority
pollutants
NOIA--National Ocean Industries Association
NOW--Nonhazardous Oilfield Waste
NPDES--The National Pollutant Discharge Elimination System
NRDC--Natural Resources Defense Council, Incorporated
NSPS--New source performance standards under section 306 of the
Clean Water Act
NTTAA--National Technology Transfer and Advancement Act
OBF--Oil-Based Drilling Fluid
OCS--Offshore Continental Shelf
OMB--Office of Management and Budget
PAH--Polynuclear Aromatic Hydrocarbon
PBMS--Performance Based Measurement System
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
RPE--Reverse Phase Extraction
SBA--Small Business Administration
SBF--Synthetic Based Drilling Fluid
SBF Development Document--Development Document for Proposed 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
SBF Economic Analysis--Economic Analysis of Proposed 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
SBF Environmental Assessment--Environmental Assessment of Proposed
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
SBREFA--Small Business Regulatory Enforcement Fairness Act
SEC--Security and Exchange Commission
SIC--Standard Industrial Classification
SPP--Suspended particulate phase
SWD--Shallow-water development model well
SWE--Shallow-water exploratory model well
TSS--Total Suspended Solids
UMRA--Unfunded Mandates Reform Act
U.S.C.--United States Code
WBF--Water-Based Drilling Fluid
For the reasons set forth in the preamble, 40 CFR Part 435 is
proposed to be amended as follows:
PART 435--OIL AND GAS EXTRACTION POINT SOURCE CATEGORY
1. The authority citation for Part 435 is revised to read as
follows:
Authority: (33 U.S.C. 1311, 1314, 1316, 1317, 1318, 1342 and
1361).
Subpart A--Offshore Subcategory
2. Section 435.11 is revised to read as follows:
Sec. 435.11 Specialized definitions.
For the purpose of this subpart:
(a) Except as provided in this section, the general definitions,
abbreviations and methods of analysis set forth in 40 CFR part 401
shall apply to this subpart.
(b) The term average of daily values for 30 consecutive days shall
be the average of the daily values obtained during any 30 consecutive
day period.
(c) The term base fluid retained on cuttings shall refer to
American Petroleum Institute Recommended Practice 13B-2 supplemented
with the specifications, sampling methods, and averaging of the
retention values provided in appendix 7 of 40 CFR part 435, subpart A.
(d) The term biodegradation rate as applied to BAT effluent
limitations and NSPS for drilling fluids and drill cuttings shall refer
to the test procedure presented in appendix 4 of 40 CFR part 435,
subpart A.
(e) The term daily values as applied to produced water effluent
limitations and NSPS shall refer to the daily measurements used to
assess compliance with the maximum for any one day.
(f) The term deck drainage shall refer to any waste resulting from
deck washings, spillage, rainwater, and
[[Page 5532]]
runoff from gutters and drains including drip pans and work areas
within facilities subject to this subpart.
(g) The term percent degraded at 120 days shall refer to the
concentration (milligrams/kilogram dry sediment) of the base fluid in
sediment relative to the intial concentration of base fluid in sediment
at the start of the test on day zero.
(h) The term percent stock base fluid degraded at 120 days minus
percent C16-C18 internal olefin degraded at 120
days shall not be less than zero shall mean that the percent base fluid
degraded at 120 days of any single sample of base fluid shall not be
less than the percent C16-C18 internal olefin
degraded at 120 days as a control standard.
(i) The term development facility shall mean any fixed or mobile
structure subject to this subpart that is engaged in the drilling of
productive wells.
(j) The term diesel oil shall refer to the grade of distillate fuel
oil, as specified in the American Society for Testing and Materials
Standard Specification for Diesel Fuel Oils D975-91, that is typically
used as the continuous phase in conventional oil-based drilling fluids.
This incorporation by reference was approved by the Director of the
Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR Part 51.
Copies may be obtained from the American Society for Testing and
Materials, 1916 Race Street, Philadelphia, PA 19103. Copies may be
inspected at the Office of the Federal Register, 800 North Capitol
Street, NW., Suite 700, Washington, DC. A copy may also be inspected at
EPA's Water Docket, 401 M Street SW., Washington, DC 20460.
(k) The term domestic waste shall refer to materials discharged
from sinks, showers, laundries, safety showers, eye-wash stations,
hand-wash stations, fish cleaning stations, and galleys located within
facilities subject to this subpart.
(l) The term drill cuttings shall refer to the particles generated
by drilling into subsurface geologic formations and carried out from
the wellbore with the drilling fluid.
(m) The term drilling fluid refers to the circulating fluid (mud)
used in the rotary drilling of wells to clean and condition the hole
and to counterbalance formation pressure. Classes of drilling fluids
are:
(1) A water-based drilling fluid has water or a water miscible
fluid as the continuous phase and the suspending medium for solids,
whether or not oil is present.
(2) A non-aqueous drilling fluid is one in which the continuous
phase is a water immiscible fluid such as an oleaginous material (e.g.,
mineral oil, enhanced mineral oil, paraffinic oil, or synthetic
material such as olefins and vegetable esters).
(3) An oil-based drilling fluid has diesel oil, mineral oil, or
some other oil, but neither a synthetic material nor enhanced mineral
oil, as its continuous phase with water as the dispersed phase. Oil-
based drilling fluids are a subset of non-aqueous drilling fluids.
(4) An enhanced mineral oil-based drilling fluid has an enhanced
mineral oil as its continuous phase with water as the dispersed phase.
Enhanced mineral oil-based drilling fluids are a subset of non-aqueous
drilling fluids.
(5) A synthetic-based drilling fluid has a synthetic material as
its continuous phase with water as the dispersed phase. Synthetic-based
drilling fluids are a subset of non-aqueous drilling fluids.
(n) The term enhanced mineral oil as applied to enhanced mineral
oil-based drilling fluid means a petroleum distillate which has been
highly purified and is distinguished from diesel oil and conventional
mineral oil in having a lower polycyclic aromatic hydrocarbon (PAH)
content. Typically, conventional mineral oils have a PAH content on the
order of 0.35 weight percent expressed as phenanthrene, whereas
enhanced mineral oils typically have a PAH content of 0.001 or lower
weight percent PAH expressed as phenanthrene.
(o) The term exploratory facility shall mean any fixed or mobile
structure subject to this subpart that is engaged in the drilling of
wells to determine the nature of potential hydrocarbon reservoirs.
(p) The term no discharge of formation oil shall mean that cuttings
contaminated with non-aqueous drilling fluids (NAFs) may not be
discharged if the NAFs contain formation oil, as determined by the GC/
MS baseline method as defined in appendix 5 to 40 CFR part 435, subpart
A, to be applied before NAFs are shipped offshore for use, or the RPE
method as defined in appendix 6 to 40 CFR part 435, subpart A, to be
applied at the point of discharge. At the discretion of the permittee,
detection of formation oil by the RPE method may be assured by the GC/
MS method, and the results of the GC/MS method shall supercede those of
the RPE method.
(q) The term maximum as applied to BAT effluent limitations and
NSPS for drilling fluids and drill cuttings shall mean the maximum
concentration allowed as measured in any single sample of the barite
for determination of cadmium and mercury content, or as measured in any
single sample of base fluid for determination of PAH content.
(r) The term maximum weighted average for well for BAT effluent
limitations and NSPS for base fluid retained on cuttings shall mean the
weighted average base fluid retention as determined by API RP 13B-2,
using the methods and averaging calculations presented in appendix 7 of
40 CFR part 435, subpart A.
(s) The term maximum for any one day as applied to BPT, BCT and BAT
effluent limitations and NSPS for oil and grease in produced water
shall mean the maximum concentration allowed as measured by the average
of four grab samples collected over a 24-hour period that are analyzed
separately. Alternatively, for BAT and NSPS the maximum concentration
allowed may be determined on the basis of physical composition of the
four grab samples prior to a single analysis.
(t) The term minimum as applied to BAT effluent limitations and
NSPS for drilling fluids and drill cuttings shall mean the minimum 96-
hour LC50 value allowed as measured in any single sample of
the discharged waste stream. The term minimum as applied to BPT and BCT
effluent limitations and NSPS for sanitary wastes shall mean the
minimum concentration value allowed as measured in any single sample of
the discharged waste stream.
(u) The term M9IM shall mean those offshore facilities continuously
manned by nine (9) or fewer persons or only intermittently manned by
any number of persons.
(v) The term M10 shall mean those offshore facilities continuously
manned by ten (10) or more persons.
(w) The term new source means any facility or activity of this
subcategory that meets the definition of ``new source'' under 40 CFR
122.2 and meets the criteria for determination of new sources under 40
CFR 122.29(b) applied consistently with all of the following
definitions:
(1) The term water area as used in the term ``site'' in 40 CFR
122.29 and 122.2 shall mean the water area and ocean floor beneath any
exploratory, development, or production facility where such facility is
conducting its exploratory, development or production activities.
(2) The term significant site preparation work as used in 40 CFR
122.29 shall mean the process of surveying, clearing or preparing an
area of the ocean floor for the purpose of constructing or placing a
development or production facility on or over the site. ``New Source''
does not include facilities covered by an existing NPDES
[[Page 5533]]
permit immediately prior to the effective date of these guidelines
pending EPA issuance of a new source NPDES permit.
(x) The term no discharge of free oil shall mean 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 to 40 CFR part
435, subpart A.
(y) The term produced sand shall refer to slurried particles used
in hydraulic fracturing, the accumulated formation sands and scales
particles generated during production. Produced sand also includes
desander discharge from the produced water waste stream, and blowdown
of the water phase from the produced water treating system.
(z) The term produced water shall refer to the water (brine)
brought up from the hydrocarbon-bearing strata during the extraction of
oil and gas, and can include formation water, injection water, and any
chemicals added downhole or during the oil/water separation process.
(aa) The term production facility shall mean any fixed or mobile
structure subject to this subpart that is either engaged in well
completion or used for active recovery of hydrocarbons from producing
formations.
(bb) The term sanitary waste shall refer to human body waste
discharged from toilets and urinals located within facilities subject
to this subpart.
(cc) The term sediment toxicity as applied to BAT effluent
limitations and NSPS for drilling fluids and drill cuttings shall refer
to ASTM E1367-92: Standard Guide for Conducting 10-day Static Sediment
Toxicity Tests with Marine and Estuarine Amphipods (Available from the
American Society for Testing and Materials, 100 Barr Harbor Drive, West
Conshohocken, PA, 19428) supplemented with the sediment preparation
procedure in appendix 3 of 40 CFR part 435, subpart A.
(dd) The term static sheen test shall refer to the standard test
procedure that has been developed for this industrial subcategory for
the purpose of demonstrating compliance with the requirement of no
discharge of free oil. The methodology for performing the static sheen
test is presented in appendix 1 to 40 CFR part 435, subpart A.
(ee) The term synthetic material as applied to synthetic-based
drilling fluid means material produced by the reaction of specific
purified chemical feedstock, as opposed to the traditional base fluids
such as diesel and mineral oil which are derived from crude oil solely
through physical separation processes. Physical separation processes
include fractionation and distillation and/or minor chemical reactions
such as cracking and hydro processing. Since they are synthesized by
the reaction of purified compounds, synthetic materials suitable for
use in drilling fluids are typically free of polycyclic aromatic
hydrocarbons (PAH's) but are sometimes found to contain levels of PAH
up to 0.001 weight percent PAH expressed as phenanthrene. Poly(alpha
olefins) and vegetable esters are two examples of synthetic materials
suitable for use by the oil and gas extraction industry in formulating
drilling fluids. Poly(alpha olefins) are synthesized from the
polymerization (dimerization, trimerization, tetramerization, and
higher oligomerization) of purified straight-chain hydrocarbons such as
C6-C14 alpha olefins. Vegetable esters are
synthesized from the acid-catalyzed esterification of vegetable fatty
acids with various alcohols. The mention of these two branches of
synthetic fluid base materials is to provide examples, and is not meant
to exclude other synthetic materials that are either in current use or
may be used in the future. A synthetic-based drilling fluid may include
a combination of synthetic materials.
(ff) The term SPP toxicity as applied to BAT effluent limitations
and NSPS for drilling fluids and drill cuttings shall refer to the
bioassay test procedure presented in appendix 2 of 40 CFR part 435,
subpart A.
(gg) The term well completion fluids shall refer to salt solutions,
weighted brines, polymers, and various additives used to prevent damage
to the well bore during operations which prepare the drilled well for
hydrocarbon production.
(hh) The term well treatment fluids shall refer to any fluid used
to restore or improve productivity by chemically or physically altering
hydrocarbon-bearing strata after a well has been drilled.
(ii) The term workover fluids shall refer to salt solutions,
weighted brines, polymers, or other specialty additives used in a
producing well to allow for maintenance, repair or abandonment
procedures.
(jj) The term 10-day LC50 shall refer to the
concentration (milligrams/kilogram dry sediment) of the base fluid in
sediment that is lethal to 50 percent of the test organisms exposed to
that concentration of the base fluids after 10-days of constant
exposure.
(kk) The term 10-day LC50 of stock base fluid minus 10-
day LC50 of C16-C18 internal olefin
shall not be less than zero shall mean that the 10-day LC50
of any single sample of the base fluid shall not be less than the
LC50 of C16-C18 internal olefin as a
control standard.
(ll) The term 96-hour LC50 shall refer to the
concentration (parts per million) or percent of the suspended
particulate phase (SPP) from a sample that is lethal to 50 percent of
the test organisms exposed to that concentration of the SPP after 96
hours of constant exposure.
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).
* * * * *
BPT Effluent Limitations--Oil and Grease
[In milligrams per liter]
----------------------------------------------------------------------------------------------------------------
Average of values for
Pollutant parameter waste source Maximum for any 1 day 30 consecutive days Residual chlorine
shall not exceed minimum for any 1 day
----------------------------------------------------------------------------------------------------------------
* * * * * *
*
Water-based:
Drilling fluids.................. (\1\).................. (\1\).................. NA
Drill cuttings................... (\1\).................. (\1\).................. NA
[[Page 5534]]
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
the entry for ``Drilling fluids and drill cuttings'' and by revising
footnote 2 and adding footnotes 5-9 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
------------------------------------------------------------------------
BAT effluent
Waste source Pollutant parameter limitation
------------------------------------------------------------------------
* * * *
* * *
Drilling fluids and drill
cuttings
* * * *
* * *
(B) For facilities located
beyond 3 miles from shore
Water-based drilling fluids SPP Toxicity........ Minimum 96-hour LC50
and drill cuttings. of the SPP shall be
3% by volume \2\.
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 fluids. .................. No discharge.
Cuttings associated with non-
aqueous drilling fluids
Stock Limitations....... Mercury............. 1 mg/kg dry weight
maximum in the
stock barite.
Cadmium............. 3 mg/kg dry weight
maximum in the
stock barite.
Polynuclear Aromatic Maximum 10 ppm wt.
Hydrocarbons (PAH). PAH based on
phenanthrene/wt. of
stock base fluid
\5\.
Sediment Toxicity... 10-day LC50 of stock
base fluid minus 10-
day LC50 of C16-C18
internal olefin
shall not be less
than zero \6\.
Biodegradation Rate. Percent stock base
fluid degraded at
120 days minus
percent C16-C18
internal olefin
degraded at 120
days shall not be
less than zero \7\.
Discharge Limitations... Diesel oil.......... No discharge.
Formation Oil....... No discharge \8\.
Base fluid retained Maximum weighted
on cuttings. average for well
shall be 10.2
percent \9\.
* * * *
* * *
------------------------------------------------------------------------
* * * *
* * *
\2\ As determined by the suspended particulate phase toxicity test
(Appendix 2).
\3\ As determined by the static sheen test (Appendix 1).
* * * *
* * *
\5\ As determined by EPA Method 1654A: Polynuclear Aromatic Hydrocarbon
Content of Oil by High Performance Liquid Chromatography with an
Ultraviolet Detector 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 (NTIS) (703/605-6000)].
\6\ As determined by ASTM E1367-92: Standard Guide for Conducting 10-day
Static Sediment Toxicity Tests with Marine and Estuarine Amphipods
(Incorporated by reference and available from the American Society for
Testing and Materials, 100 Barr Harbor Drive, West Conshohocken, PA,
19428) supplemented with the sediment preparation procedure in
Appendix 3.
\7\ As determined by the biodegradation test (Appendix 4).
\8\ As determined by the GC/MS baseline and assurance method (Appendix
5), and by the RPE method applied to drilling fluid removed from
cuttings at primary shale shakers (Appendix 6).
[[Page 5535]]
\9\ Maximum permissible retention of base fluid on wet cuttings averaged
over drill intervals using non-aqueous drilling fluids as determined
by retort method (Appendix 7).
5. In Sec. 435.14 the table is amended by revising entry B under
the entry for ``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
----------------------------------------------------------------------------------------------------------------
Waste source Pollutant parameter BCT effluent limitation
----------------------------------------------------------------------------------------------------------------
* * * * * *
*
Drilling fluids and drill cuttings
* * * * * *
*
(B) For facilities located beyond 3
miles from shore
Water-based drilling fluids and Free oil............................. No discharge \2\.
drill cuttings.
Non-aqueous drilling fluids......... ................................... No discharge.
Cuttings associated with non-aqueous Free oil............................. No discharge \2\.
drilling fluids.
* * * * * *
*
----------------------------------------------------------------------------------------------------------------
\2\ As determined by the static sheen test (Appendix 1).
6. In Sec. 435.15 the table is amended by revising entry B under
the entry for ``Drilling fluids and drill cuttings'' and by revising
footnote 2 and adding footnotes 5-9 to read as follows:
Sec. 435.15 Standards of performance for new sources (NSPS).
* * * * *
New Source Performance Standards
------------------------------------------------------------------------
Waste source Pollutant parameter NSPS
------------------------------------------------------------------------
* * * *
* * *
Drilling fluids and drill
cuttings
* * * *
* * *
(B) For facilities located
beyond 3 miles from shore
Water-based drilling fluids SPP Toxicity........ Minimum 96-hour LC50
and drill cuttings. of the SPP shall be
3% by volume \2\.
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 fluids. .................. No discharge.
Cuttings associated with non- ..................
aqueous drilling fluids
Stock Limitations....... Mercury............. 1 mg/kg dry weight
maximum in the
stock barite.
Cadmium............. 3 mg/kg dry weight
maximum in the
stock barite.
Polynuclear Aromatic Maximum 10 ppm wt.
Hydrocarbons (PAH). PAH based on
phenanthrene/wt. of
stock base fluid
\5\.
Sediment Toxicity... 10-day LC50 of stock
base fluid minus 10-
day LC50 of C16-C18
internal olefin
shall not be less
than zero \6\.
Biodegradation Rate. Percent stock base
fluid degraded at
120 days minus
percent C16-C18
internal olefin
degraded at 120
days shall not be
less than zero \7\.
Discharge Limitations... Diesel oil.......... No discharge.
Free oil............ No discharge \3\.
Formation oil....... No discharge \8\.
Base fluid retained Maximum weighted
on cuttings. average for well
shall be 10.2
percent \9\.
[[Page 5536]]
* * * *
* * *
------------------------------------------------------------------------
* * * *
*
\2\ As determined by the suspended particulate phase toxicity test
(Appendix 2).
\3\ As determined by the static sheen test (Appendix 1).
* * * *
*
\5\ As determined by EPA Method 1654A: Polynuclear Aromatic Hydrocarbon
Content of Oil by High Performance Liquid Chromatography with an
Ultraviolet Detector 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 (NTIS) (703/605-6000)].
\6\ As determined by ASTM E1367-92: Standard Guide for Conducting 10-day
Static Sediment Toxicity Tests with Marine and Estuarine Amphipods
(Incorporated by reference and available from the American Society for
Testing and Materials, 100 Barr Harbor Drive, West Conshohocken, PA,
19428) supplemented with the sediment preparation procedure in
Appendix 3.
\7\ As determined by the biodegradation test (Appendix 4).
\8\ As determined by the GC/MS baseline and assurance method (Appendix
5), and by the RPE method applied to drilling fluid removed from
cuttings at primary shale shakers (Appendix 6).
\9\ Maximum permissible retention of base fluid on wet cuttings averaged
over drill intervals using non-aqueous drilling fluids as determined
by retort method (Appendix 7).
7. Subpart A is amended by adding Appendices 3 through 7 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 should 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:
[GRAPHIC] [TIFF OMITTED] TP03FE99.041
2. Determine the density (g/mL) of the wet control or dilution
sediment. This will be used to determine total volume of wet
sediment needed for the various test treatments.
[GRAPHIC] [TIFF OMITTED] TP03FE99.042
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:
[GRAPHIC] [TIFF OMITTED] TP03FE99.043
Determine the amount of dry sediment in kilograms (kg) required
for each concentration:
[GRAPHIC] [TIFF OMITTED] TP03FE99.044
Finally, determine the amount of base fluid required to spike
the control sediment at each concentration:
[GRAPHIC] [TIFF OMITTED] TP03FE99.045
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
difficulty of homogeneously mixing base fluid with sediment, it is
important to demonstrate that the base fluid is evenly mixed with
sediment. The sediment should 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 should be
taken prior to distribution into test containers. After the test
sediment is distributed to test containers, an additional three
sediment samples should be taken from three test containers to
ensure proper distribution of base fluid within test containers.
Base-fluid content results should 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 should be remixed. Tests should
not begin until the CV is determined to be below the maximum limit
of 20%. During the test, a minimum of three replicate containers
should be sampled to determine base-fluid content during each
sampling period.
[[Page 5537]]
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
should bracket the LC50, which is the desired endpoint. The results
for the base fluids will 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 Solid-Phase Test System
Summary of Method
This analytical method determines the biodegradation potential
of mineral, paraffinic, and diesel oils as well as synthetic
materials that are used as base fluids in the formulation of
drilling fluids. The base fluids are mixed with sediment at an
initial concentration of 500 mg/kg dry sediment, and placed under
flowing seawater at 12 deg.C. Base fluid concentration measurements
are made at Days 0, 14, 28, 56, and 120. This method uses two
parameters, base-fluid content and redox potential in both poisoned
and unpoisoned sediment, to assess the rate of biodegradation of
base fluids.
Sample Requirements
1. The exposure system is a flowing seawater system providing a
laminar flow over replicate test containers for a test duration of
120 days. For each base fluid there are two treatments: (1) base
fluid-dosed sediment; and (2) base fluid-dosed sediment poisoned
with biocide (used to measure the abiotic degradation of the base
fluids).
2. To prevent cross-contamination, individual exposure tables
should be used for each treatment and control. Exposure tables
should be constructed of non-contaminating material and should be
large enough to hold the required number of replicate test
containers. Seawater should enter one end of the table, flow
uniformly over test containers, and exit the opposite end of the
table.
3. Sampling should be conducted on Days 0, 14, 28, 56, and 120.
Sampling consists of three replicate samples taken on each sampling
day for determination of redox potential and base-fluid content.
4. For Day 0 sampling, all samples should be taken from the
initial batch of test treatment sediment prior to distribution into
replicate exposure containers. Sufficient test treatment sediment
must be made for a minimum of 30 replicate samples to be taken
throughout the study (see Table 1).
Table 1.--Replicate Requirements per Treatment and Control Tests
[Replication per sampling period]
----------------------------------------------------------------------------------------------------------------
Unpoisoned sediment Poisoned sediment
-------------------------------------------------------------------
Sampling period Base-fluid Base-fluid
Redox potential content* Redox potential Content*
----------------------------------------------------------------------------------------------------------------
DAY 0....................................... 3 3 3 3
DAY 14...................................... 3** 3 3** 3
DAY 28...................................... 3 3
DAY 56...................................... 3 3
DAY 120..................................... 3 3
----------------------------------------------------------------------------------------------------------------
Totals Samples.......................... 6 15 6 15
----------------------------------------------------------------------------------------------------------------
* Sampling for base-fluid content is destructive, therefore samples must be taken from a different replicate set
of three sampling containers for each sampling date.
** Sampling for redox potential is non-destructive, therefore samples may be taken from the same replicate set
of three sample containers for each sampling date after Day 0.
Mixing Methods
Because base fluids are strongly hydrophobic and do not readily
mix with sediments, 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 will 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 using Formula 1. This is
required to determine the weight of wet sediment needed to prepare
the test concentration of 500 mg of base fluid per kg of dry
sediment (500 ppm).
[GRAPHIC] [TIFF OMITTED] TP03FE99.046
2. Determine the density (g/mL) of the wet control or dilution
sediment. This will be used to determine total volume of wet
sediment needed for the various test treatments.
[GRAPHIC] [TIFF OMITTED] TP03FE99.047
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:
[[Page 5538]]
Determine the amount of wet sediment required:
[GRAPHIC] [TIFF OMITTED] TP03FE99.048
Determine the amount of dry sediment in kilograms (kg) required
for each concentration:
[GRAPHIC] [TIFF OMITTED] TP03FE99.049
Finally, determine the amount of base fluid to provide the
initial test concentration of 500 mg/kg dry sediment:
[GRAPHIC] [TIFF OMITTED] TP03FE99.050
4. Based on the required number (42) and size (approximately 500
mL) of samples, the approximate volume of sediment needed is 25 L.
Mixing should be performed in 5 L batches, then combined and
remixed. 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.
5. Secondary mixing should be conducted in a large container
(i.e., cement mixer) and mixing should be for a minimum of 10
minutes. Day 0 samples will be taken from this batch of test
sediment.
6. Biocide additions are to be mixed after all other mixing is
complete.
Base-Fluid Content
Because of difficulty of homogeneously mixing base fluid with
sediment, it is important to demonstrate that the base fluid is
evenly mixed with sediment. The sediment should 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 25L batch of sediment test concentration, a minimum
of three replicate sediment samples will 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 should be reported within 48 hours of mixing.
Measured and nominal concentrations should be reported for initial
test concentrations. 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 should be
remixed. Tests should not begin until the CV is determined to be
below the maximum limit of 20%. During the test, a minimum of three
replicate containers should be sampled to determine base-fluid
content during each sampling period.
Water Quality Measurements
The following water quality measurements of the overlying water
should be taken daily: dissolved oxygen (DO), pH, temperature, and
salinity.
Measurement of Redox Potential
1. The oxidation-reduction (redox) potential of a sediment is a
quantitative expression of its oxidizing or reducing tendency. Redox
potential is expressed as an Eh value, Eh
being the electron motive force (in mV) of an oxidation-reduction
system referred to as a standard hydrogen half-cell. Positive
Eh values are characteristic of well oxygenated, coarse
sediments or those with very low concentrations of organic matter.
Conversely, negative Eh values occur in deoxygenated
sediments rich in organic matter and largely consisting of fine
particles. A redox profile follows changes in redox potential at
increasing depths from the sediment surface.
2. The redox potential should be measured using a combination
platinum/reference (Ag/AgCL) electrode held in an adjustable retort
stand, one revolution resulting in a lowering of the probe by 5 mm.
Readings should be taken after one minute and values for Zobell's
solution (g L-1; potassium ferrocyanide, 1.399; potassium
ferricyanide, 1.087; potassium chloride, 7.456) and sea water should
be monitored after each depth profile. Actual readings should be
adjusted to Eh by adding 198.
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.
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 method.
2.0 Summary of Method
2.1 Analysis of NAF for crude oil contamination is a step-wise
process. Qualitative assessment of the presence or absence of crude
oil is performed first. If crude oil is detected in this qualitative
assessment, quantitative analysis of the crude oil concentration is
performed.
2.2 A sample of NAF is centrifuged, to obtain a solids free
supernate.
2.3 The sample to be tested 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.
2.6 If crude oil is detected in the qualitative analysis,
quantitative analysis is performed by calibrating the GC/MS using a
designated NAF spiked with known concentrations of a designated oil.
[[Page 5539]]
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 is cleaned by rinsing with solvent and baking at
400 deg.C for a minimum of 1 hour.
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
should 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)
should 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 39 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. Used
when necessary for sample dilution.
7.2 Standards--Prepare from pure individual standard materials
or purchased 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 will 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 will 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.
[[Page 5540]]
7.2.4 GC/MS system performance test mix (SPTM) standards--The
SPTM standards should 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 below 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 will 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 7.2.3), 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, with the exception that only ``Jar 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--bracketing authentic samples every 12 hours with precision and
recovery standard) and the initial demonstration exercise described
in Section 9.2.
7.2.7 Stability of standards
7.2.7.1 When not used, standards are stored in the dark, at -5
to -20 deg.C in screw-capped vials with PTFE-lined lids. A mark is
placed on the vial at the level of the solution so that solvent loss
by evaporation can be detected. The vial is brought 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. Standard will 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 NAF samples and base fluid samples are collected in 100-to
200-mL glass bottles with PTFE-or aluminum foil lined caps.
8.2 Samples collected in the field will 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 tests experience samples
should be analyzed within seven to ten days of collection and
extracts analyzed within seven days of preparation.
8.4 After completion of GC/MS analysis, extracts should be
refrigerated at ca. 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 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 is 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 is established as described in Section 9.2.
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) and to repeat the initial demonstration procedure
described in Section 9.2.
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.
9.1.4 An 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.
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.
9.1.6 Analysis of a sample of the clean NAF(s) (as sent from
the supplier--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) that the analysis system is in
control. These procedures are described in Section 11.6.
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 is 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.
Analyze these aliquots using the procedures outlined in Section 11.
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.
[[Page 5541]]
9.3 Blanks--Rinse glassware and centrifuge tubes used in the
method with ca. 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) and analyze a 1-L aliquot
of the blank sample using the procedure in Section 11. Compute
results per Section 12.
9.4 Matrix spike sample--Prepare a matrix spike sample
according to procedure outlined in Section 7.2.6. 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.
9.5 Duplicates--A duplicate field sample is prepared according
to procedures outlined in Section 7.3 and analyzed according to
Section 11. The relative percent difference (RPD) of the calculated
concentrations should be less than 15%.
9.5.1 Analyze each of the duplicates per the procedure in
Section 11 and compute the results per Section 12.
9.5.2 Calculate the relative percent difference (RPD) between
the two results per the following equation:
[GRAPHIC] [TIFF OMITTED] TP03FE99.051
where:
D1 = Concentration of crude oil in the sample
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
reanalyzed.
9.6 Preparation of the clean NAF sample is performed according
to procedures outlined in Section 7.3 except that the clean NAF
(drilling fluid that has not been circulated downhole) is used.
Ultimately the oil-equivalent concentration from the TIC or EIP
signal measured in the clean NAF sample will be subtracted from the
corresponding authentic field samples in order to calculate the true
contaminant concentration (% oil) in the field samples (see Section
12).
9.7 The specifications contained in this method can be met if
the apparatus used is calibrated properly, then maintained in a
calibrated state. The standards used for initial precision and
recovery (Section 9.2) and ongoing precision and recovery (Section
11.6) 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 below. Perform the GC/MS system
hardware-tune as outlined by the manufacture. The gas chromatograph
is 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 are met.
Table 1.--Gas Chromatograph/Mass Spectrometer (GC/MS) Operating Conditions
----------------------------------------------------------------------------------------------------------------
Parameter Setting
----------------------------------------------------------------------------------------------------------------
Injection port..................... 280 deg.C.
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 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 Times for Compounds
------------------------------------------------------------------------
Approximate
Compound Retention Time
(minutes)
------------------------------------------------------------------------
Toluene................................................. 5.6
Octane, n-C8............................................ 7.2
Ethylbenzene............................................ 10.3
1,2,4-Trimethylbenzene.................................. 16.0
Decane, n-C10........................................... 16.1
TCB (Internal Standard)................................. 21.3
Dodecane, n-C12......................................... 22.9
1-Methylnaphthalene..................................... 26.7
1-Tetradecene........................................... 28.4
Tetradecane, n-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 are primarily used to establish retention times and
establish qualitative detection limits.
[[Page 5542]]
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 above.
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 can be used as the primary technique
for quantifying crude oil in NAFs. The EIP Area Integration method
can be used as a confirmatory technique for NAFs. The EIP Area
Integration method should 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 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 r\2\ value for the linear regression
curve should be 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 r\2\ value for the each of the EIP
linear regression curves should be 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
7.2.3), 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 summarizes the recommended operating conditions for the
GC/MS. Retention times for the n-alkanes obtained under these
conditions are given in Table 2. Other columns, chromatographic
conditions, or detectors may be used if initial precision and
accuracy requirements (Section 9.2) are met. The system is
calibrated according to the procedures outlined in Section 10, and
verified every 12 hours according to Section 11.6.
11.2.1 Samples should be prepared (extracted) in a batch of no
more than 20 samples. The batch should consist of 20 authentic
samples, 1 blank (Section 9.3), 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 is run on the GC/MS where the 3
SPTM standards (Section 7.2.4) containing internal standard are
analyzed first, followed by analysis of the four GC/MS crude oil/
drilling fluid calibration standards (Section 7.2.5), 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
should 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.
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).
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 reanalyze.
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 are used in the calculation of oil concentration in the
samples (see Section 12).
Table 3.--Recommended Ion Mass Numbers
------------------------------------------------------------------------
Typical
Corresponding aromatic retention
Selected ion mass numbers compounds times (in
minutes)
------------------------------------------------------------------------
91............................. Methylbenzene.......... 6.0
Ethylbenzene........... 10.3
1,4-Dimethylbenzene.... 10.9
1,3-Dimethylbenzene.... 10.9
1,2-Dimethylbenzene.... 11.9
105............................ 1,3,5-Trimethylbenzene. 15.1
1,2,4-Trimethylbenzene. 16.0
1,2,3-Trimethylbenzene. 17.4
156............................ 2,6-Dimethylnaphthalene 28.9
1,2-Dimethylnaphthalene 29.4
[[Page 5543]]
1,3-Dimethylnaphthalene 29.7
------------------------------------------------------------------------
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 for schematic
flowchart.
11.3.1 Qualitative identification is 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). Crude
oil is 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 should be suspected and quantitative analysis
should 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). 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 determine the
presence of any target aromatics. Using the integration techniques
outlined in Section 10.4.2 to 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 it 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 should 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 are 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) 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. 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).
11.6.4 Retention times--Retention time of the internal
standard. The absolute retention time of the TCB internal standard
should 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.
12.0 Calculations
The concentration of oil in NAFs drilling fluids is 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 quantitation 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 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.
[[Page 5544]]
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 form the American Chemical Society's Department of
Government Relations and Science Policy, 1155 16th Street NW,
Washington, D.C. 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.
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.
5.0 Safety
5.1 The toxicity or carcinogenicity of each reagent used in
this method has not been precisely determined; however, each
chemical should be treated as a potential health hazard. Exposure to
these chemicals should be reduced to the lowest possible level.
Material Safety Data Sheets (MSDSs) should be available for all
reagents.
[[Page 5545]]
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)
should 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 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, 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''x7.5''x7.5'' 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.
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.
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.
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.
9.1.4 The laboratory should 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), corresponding NAF reference
blanks (Section 9.6), a set of spiked duplicate samples blank
(Section 9.4), 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 should
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
will be analyzed 10 times, and successful demonstration will yield
the following average results for the data set:
----------------------------------------------------------------------------------------------------------------
0.1% oil 1 %oil 2 %oil
----------------------------------------------------------------------------------------------------------------
Detected in <20% of samples........ Detected in >75% of samples Detected in <90% of samples.
----------------------------------------------------------------------------------------------------------------
[[Page 5546]]
9.3 Sample duplicates.
9.3.1 The laboratory must prepare and analyze (Section 11.2 and
11.4) 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.
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
reanalyzed.
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)
will be spiked with 1% (by volume) of suitable reference crude oil
and analyzed as field samples, as described in Section 11. 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 must 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 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.
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, 0.45m 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.
[[Page 5547]]
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.
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.
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)
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 Observe the presence or absence of fluorescence for the
sample cartridge (in right position) relative to the NAF reference
blank.
11.4.5 The presence of fluorescence indicates the detection of
crude oil contamination. The absence of fluorescence in the sample
cartridge indicates that the drilling fluid 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 oleaginous base fluid from cuttings generated during a drilling
operation. It is a retort test which measures all oily material
(base fluid) and water released from a cuttings sample when heated
in a calibrated and properly operating ``Retort'' instrument.
b. In this retort test a known weight of cuttings is heated in
the retort chamber to vaporize the liquids associated with the
sample. The 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 (location, method,
frequency). The sampling procedure in a given area may be specified
by local or governmental rules.
2. Equipment
a. Retort instrument--The recommended retort instrument has a
50-cm\3\ 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-cm\3\
Precision: 0.25-cm\3\
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 930 70 deg.F (500 38 deg.C).
b. Liquid receiver (10-cm\3\, 20-cm\3\, or 50-cm\3\)--the 10-
cm\3\ and 20-cm\3\ receivers are specially designed cylindrical
glassware with rounded bottom to facilitate cleaning and funnel-
shaped top to catch falling drops.
1. Receiver specifications.
Total volume: 10-cm\3\............. 20-cm\3\.............. 50-cm\3\
Precision (0 to 100%).............. 0.05cm\3\. 0.05cm\3\. 0.05cm\3\ nom.
Outside diameter................... 10-mm................. 13-mm ...........................
[[Page 5548]]
Wall thickness..................... 1.50.1mm.. 1.20.1mm.. ...........................
Frequency of graduation marks (0 to 0.10cm\3\............. 0.10cm\3\............. 1.0cm\3\
100%).
Calibration........................ To contain ``TC'' 20 deg.C.............. ...........................
Scale.............................. cm\3\................. cm\3\ cm\3\
Note: Verification of receiver volume. The receiver volume
should be verified gravimetrically. The procedure and calculations
are in Par. 5.
2. Material--Pyrex or equivalent glass.
c. Toploading balance--capable of weighing 2000 g and precision
of 0.1g.
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 Par.
1)
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 must 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 (base fluid) from the cuttings as
follows:
1. Mass of the wet cuttings sample (MD) equals the
mass of the retort assembly (A).
Mw = B-A (a)
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 (b)
3. Mass of the 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) (c)
Note: Assuming the density of water is 1 g/cm3, the
volume of water is equivalent to the mass of the water.
b. Mass balance requirement:
The sum of MD, MBF, and V should be within
5% of the mass of the wet sample.
(MD + MBF + V)/Mw = 0.95 to 1.05
The procedure should 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 weight percent base fluid retained on the cuttings (%BF)
is equal to 100 times the mass of the base fluid (MBF)
divided by the mass of the wet cuttings sample (Mw).
%BF = (MBF/Mw) x 100
3. The %BF is determined for all cuttings wastestreams,
including fines, and is associated with a respective length of hole
drilled (L in feet) and bit diameter (d in inches).
4. Any cuttings or fines that are retained for no discharge are
included in the weighted average with a %BF value of zero.
5. Each cuttings or fines sample corresponds to a wastestream
fraction Xw (unitless), and should be representative for
a certain length of hole drilled L (feet), using a drill bit of a
specific diameter d (inches). The wastestream fraction
(Xw) is the weight of discharge in each stream calculated
as a fraction of total cuttings (including fines) discharge. The
weighted average of %BF for the entire wastestream is equal to the
sum of %BF times the wastestream fraction (Xw) times the
length of hole (L) at given diameter times the square of the
diameter (d2) divided by the sum of the wastestream
fraction (Xw) times the length of the hole (L) at given a
diameter times the square of the diameter (d\2\).
Weighted average of %BF = (%BF x Xw x L x
d\2\)/ ( Xw x L x d2)
5. Verification of Liquid Receiver Volume
a. This procedure is used to verify that the liquid receiver
meets specifications stated in Par. 2b.
b. Equipment:
1. Distilled water.
2. Glass thermometer--to measure ambient temperature
0.1 deg.F (0.1 deg.C).
[[Page 5549]]
3. Toploading balance--precision of 0.1 g.
4. Syringe or pipette--10-cm\3\ or larger.
c. Procedure:
1. Allow receiver and distilled water to reach ambient
temperature. Record temperature.
2. Place the clean, empty receiver with its base on the balance
and tare to zero.
3. While the receiver is on the balance, fill it to the various
graduation marks (2, 4, 6, 8, 10-cm\3\ for the 10-cm\3\ receiver, 4,
8, 12, 16, 20-cm\3\ for the 20-cm\3\, and 10, 20, 30, 40, and 50-
cm\3\ for the 50-cm\3\ receiver) with distilled water. Using a
pipette or syringe, carefully fill the receiver to the desired
graduation mark without leaving water droplets on the walls of the
receiver.
4. Record weights for the incremental volumes, IV, of water at
the specific graduation marks, WIV, grams.
d. Calculation:
1. Calculate volume of the receiver at each mark,
VMARK, using density of water Table 1.
VMARK = (WIV, g)/(Density of Water, g/cm\3\)
(a)
Table 1.--Density of Water
------------------------------------------------------------------------
deg.F deg.C Density, g/cm \3\
------------------------------------------------------------------------
59.0.............................. 15.0 0.9991
59.9.............................. 15.5 0.9991
60.8.............................. 16.0 0.9990
61.7.............................. 16.5 0.9989
62.6.............................. 17.0 0.9988
63.5.............................. 17.5 0.9987
64.4.............................. 18.0 0.9986
65.3.............................. 18.5 0.9985
66.2.............................. 19.0 0.9984
67.1.............................. 19.5 0.9983
68.0.............................. 20.0 0.9982
68.9.............................. 20.5 0.9981
69.8.............................. 21.0 0.9980
70.7.............................. 21.5 0.9979
71.6.............................. 22.0 0.9977
72.5.............................. 22.5 0.9976
73.4.............................. 23.0 0.9975
74.3.............................. 23.5 0.9974
75.2.............................. 24.0 0.9973
76.1.............................. 24.5 0.9971
77.0.............................. 25.0 0.9970
77.9.............................. 25.5 0.9969
78.8.............................. 26.0 0.9968
79.7.............................. 26.5 0.9966
80.6.............................. 27.0 0.9965
81.5.............................. 27.5 0.9964
82.4.............................. 28.0 0.9962
83.3.............................. 28.5 0.9961
84.2.............................. 29.0 0.9959
85.1.............................. 29.5 0.9958
86.0.............................. 30.0 0.9956
86.9.............................. 30.5 0.9955
87.8.............................. 31.0 0.9953
88.7.............................. 31.5 0.9952
89.6.............................. 32.0 0.9950
90.5.............................. 32.5 0.9949
91.4.............................. 33.0 0.9947
92.3.............................. 33.5 0.9945
93.2.............................. 34.0 0.9944
94.1.............................. 34.5 0.9942
95.0.............................. 35.0 0.9940
------------------------------------------------------------------------
Addendum A--Sampling of Cuttings Discharge Streams for Use With API
Recommended Practice 13B-2
Sampling Locations
1. Each individual discharge stream should be sampled and
tested. These may include the discharge streams from the primary
shakers, the secondary shakers, and any other cuttings separation
device, such as a centrifuge, whose discharge is dumped directly to
the environment. The weight of discharge in each stream should be
measured and calculated as a fraction of total cuttings discharge,
Xw. The wastestream fraction, XW, is used in
the weighted average percent base fluid in cuttings. Each sample
should report the respective linear feet of hole drilled represented
by this sample (L in feet), and the drill bit diameter (d in
inches).
2. It is essential that the samples be representative of the
discharge stream. Sampling should be conducted to avoid the serious
consequences of error, i.e., bias or inaccuracy. They should be
caught 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, shaker samples should be taken as the cuttings are
coming off the shaker and not from of a holding container downstream
where separation of larger particles from the liquid can take place.
3. A simple schematic diagram of the solids control system being
used shall be provided indicating where the samples were taken.
Sample Size and Handling
1. The sample size should be about one quart (or liter). A
viscosity cup is a suitable and usually available container for
catching the sample. The sample can be transferred to a quart jar if
the retort measurement is not going to be made immediately. Mark the
container to clearly identify each sample.
[[Page 5550]]
2. Before pouring sample into retort cup, it should be made
homogeneous by gentle mixing such as hand stirring or shaking of a
jar. The bottom of the container should be examined to be sure that
solids are not sticking to it. For best results, the sample should
be run immediately after stirring and no more than two hours after
catching the sample. Do not discard sample before weight percent
synthetic has been calculated and results are within prescribed
limits noted in the analytical method. Rerunning the retort test may
be necessary.
Type of Sample and Sampling Frequency
3. Samples should represent steady state drilling operations
after obtaining bottoms-up. They should be time lagged to obtain the
actual depth of origin of the formation cuttings rather than the
drilling depth at the time the sample was caught. Samples should not
be taken at any time when there are not newly generated formation
cuttings in the discharge stream.
4. During drilling operations, at least one sample per day
should be caught and tested. In fast drilling, a sample should be
caught for every 500 feet of hole drilled up to a maximum of three
samples per day.
Subpart D--Coastal Subcategory
8. Section 435.41 is revised to read as follows:
Sec. 435.41 Specialized definitions.
For the purpose of this subpart:
(a) Except as provided in this section, the general definitions,
abbreviations and methods of analysis set forth in 40 CFR part 401
shall apply to this subpart.
(b) The term average of daily values for 30 consecutive days shall
be the average of the daily values obtained during any 30 consecutive
day period.
(c) The term base fluid retained on cuttings shall refer to
American Petroleum Institute Recommended Practice 13B-2 supplemented
with the specifications, sampling methods, and averaging of the
retention values provided in Appendix 7 of 40 CFR part 435, subpart A.
(d) The term biodegradation rate as applied to BAT effluent
limitations and NSPS for drilling fluids and drill cuttings shall refer
to the test procedure presented in appendix 4 of 40 CFR part 435,
subpart A.
(e) The term Cook Inlet refers to coastal locations north of the
line between Cape Douglas on the West and Port Chatham on the east.
(f) The term daily values as applied to produced water effluent
limitations and NSPS shall refer to the daily measurements used to
assess compliance with the maximum for any one day.
(g) The term deck drainage shall refer to any waste resulting from
deck washings, spillage, rainwater, and runoff from gutters and drains
including drip pans and work areas within facilities subject to this
subpart.
(h) The term percent degraded at 120 days shall refer to the
concentration (milligrams/kilogram dry sediment) of the base fluid in
sediment relative to the initial concentration of base fluid in
sediment at the start of the test on day zero.
(i) The term percent stock base fluid degraded at 120 days minus
percent C16-C18 internal olefin degraded at 120
days shall not be less than zero shall mean that the percent base fluid
degraded at 120 days of any single sample of base fluid shall not be
less than the percent C16-C18 internal olefin
degraded at 120 days as a control standard.
(j) The term development facility shall mean any fixed or mobile
structure subject to this subpart that is engaged in the drilling of
productive wells.
(k) The term dewatering effluent means wastewater from drilling
fluids and drill cuttings dewatering activities (including but not
limited to reserve pits or other tanks or vessels, and chemical or
mechanical treatment occurring during the drilling solids separation/
recycle/disposal process).
(l) The term diesel oil shall refer to the grade of distillate fuel
oil, as specified in the American Society for Testing and Materials
Standard Specification for Diesel Fuel Oils D975-91, that is typically
used as the continuous phase in conventional oil-based drilling fluids.
This incorporation by reference was approved by the Director of the
Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51.
Copies may be obtained from the American Society for Testing and
Materials, 1916 Race Street, Philadelphia, PA 19103. Copies may be
inspected at the Office of the Federal Register, 800 North Capitol
Street, NW, Suite 700, Washington, DC. A copy may also be inspected at
EPA's Water Docket, 401 M Street SW., Washington, DC 20460.
(m) The term domestic waste shall refer to materials discharged
from sinks, showers, laundries, safety showers, eye-wash stations,
hand-wash stations, fish cleaning stations, and galleys located within
facilities subject to this subpart.
(n) The term drill cuttings shall refer to the particles generated
by drilling into subsurface geologic formations and carried out from
the wellbore with the drilling fluid.
(o) The term drilling fluid refers to the circulating fluid (mud)
used in the rotary drilling of wells to clean and condition the hole
and to counterbalance formation pressure. Classes of drilling fluids
are:
(1) A water-based drilling fluid has water or a water miscible
fluid as the continuous phase and the suspending medium for solids,
whether or not oil is present.
(2) A non-aqueous drilling fluid is one in which the continuous
phase is a water immiscible fluid such as an oleaginous material (e.g.,
mineral oil, enhanced mineral oil, paraffinic oil, or synthetic
material such as olefins and vegetable esters).
(3) An oil-based drilling fluid has diesel oil, mineral oil, or
some other oil, but neither a synthetic material nor enhanced mineral
oil, as its continuous phase with water as the dispersed phase. Oil-
based drilling fluids are a subset of non-aqueous drilling fluids.
(4) An enhanced mineral oil-based drilling fluid has an enhanced
mineral oil as its continuous phase with water as the dispersed phase.
Enhanced mineral oil-based drilling fluids are a subset of non-aqueous
drilling fluids.
(5) A synthetic-based drilling fluid has a synthetic material as
its continuous phase with water as the dispersed phase. Synthetic-based
drilling fluids are a subset of non-aqueous drilling fluids.
(p) The term enhanced mineral oil as applied to enhanced mineral
oil-based drilling fluid means a petroleum distillate which has been
highly purified and is distinguished from diesel oil and conventional
mineral oil in having a lower polycyclic aromatic hydrocarbon (PAH)
content. Typically, conventional mineral oils have a PAH content on the
order of 0.35 weight percent expressed as phenanthrene, whereas
enhanced mineral oils typically have a PAH content of 0.001 or lower
weight percent PAH expressed as phenanthrene.
(q) The term exploratory facility shall mean any fixed or mobile
structure subject to this subpart that is engaged in the drilling of
wells to determine the nature of potential hydrocarbon reservoirs.
(r) The term no discharge of formation oil shall mean that cuttings
contaminated with non-aqueous drilling fluids (NAFs) may not be
discharged if the NAFs contain formation oil, as determined by the GC/
MS baseline
[[Page 5551]]
method as defined in appendix 5 to 40 CFR part 435, subpart A, to be
applied before NAFs are shipped offshore for use, or the RPE method as
defined in appendix 6 to 40 CFR part 435, subpart A, to be applied at
the point of discharge. At the discretion of the permittee, detection
of formation oil by the RPE method may be assured by the GC/MS method,
and the results of the GC/MS method shall supercede those of the RPE
method.
(s) The term garbage means all kinds of victual, domestic, and
operational waste, excluding fresh fish and parts thereof, generated
during the normal operation of coastal oil and gas facility and liable
to be disposed of continuously or periodically, except dishwater,
graywater, and those substances that are defined or listed in other
Annexes to MARPOL 73/78. A copy of MARPOL may be inspected at EPA's
Water Docket; 401 M Street SW, Washington DC 20460
(t) The term maximum as applied to BAT effluent limitations and
NSPS for drilling fluids and drill cuttings shall mean the maximum
concentration allowed as measured in any single sample of the barite
for determination of cadmium and mercury content, or as measured in any
single sample of base fluid for determination of PAH content.
(u) The term maximum weighted average for well for BAT effluent
limitations and NSPS for base fluid retained on cuttings shall mean the
weighted average base fluid retention as determined by API RP 13B-2,
using the methods and averaging calculations presented in appendix 7 of
40 CFR part 435, subpart A.
(v) The term maximum for any one day as applied to BPT, BCT and BAT
effluent limitations and NSPS for oil and grease in produced water
shall mean the maximum concentration allowed as measured by the average
of four grab samples collected over a 24-hour period that are analyzed
separately. Alternatively, for BAT and NSPS the maximum concentration
allowed may be determined on the basis of physical composition of the
four grab samples prior to a single analysis.
(w) The term minimum as applied to BAT effluent limitations and
NSPS for drilling fluids and drill cuttings shall mean the minimum 96-
hour LC50 value allowed as measured in any single sample of
the discharged waste stream. The term minimum as applied to BPT and BCT
effluent limitations and NSPS for sanitary wastes shall mean the
minimum concentration value allowed as measured in any single sample of
the discharged waste stream.
(x) The term M9IM shall mean those offshore facilities continuously
manned by nine (9) or fewer persons or only intermittently manned by
any number of persons.
(y) The term M10 shall mean those offshore facilities continuously
manned by ten (10) or more persons.
(z)(1) The term new source means any facility or activity of this
subcategory that meets the definition of ``new source'' under 40 CFR
122.2 and meets the criteria for determination of new sources under 40
CFR 122.29(b) applied consistently with all of the following
definitions:
(i) The term water area as used in the term ``site'' in 40 CFR
122.29 and 122.2 shall mean the water area and water body floor beneath
any exploratory, development, or production facility where such
facility is conducting its exploratory, development or production
activities.
(ii) The term significant site preparation work as used in 40 CFR
122.29 shall mean the process of surveying, clearing or preparing an
area of the water body floor for the purpose of constructing or placing
a development or production facility on or over the site.
(2) ``New source'' does not include facilities covered by an
existing NPDES permit immediately prior to the effective date of these
guidelines pending EPA issuance of a new source NPDES permit.
(aa) The term no discharge of free oil shall mean 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 to 40 CFR part
435, subpart A.
(bb) The term produced sand shall refer to slurried particles used
in hydraulic fracturing, the accumulated formation sands and scales
particles generated during production. Produced sand also includes
desander discharge from the produced water waste stream, and blowdown
of the water phase from the produced water treating system.
(cc) The term produced water shall refer to the water (brine)
brought up from the hydrocarbon-bearing strata during the extraction of
oil and gas, and can include formation water, injection water, and any
chemicals added downhole or during the oil/water separation process.
(dd) The term production facility shall mean any fixed or mobile
structure subject to this subpart that is either engaged in well
completion or used for active recovery of hydrocarbons from producing
formations. It includes facilities that are engaged in hydrocarbon
fluids separation even if located separately from wellheads.
(ee) The term sanitary waste shall refer to human body waste
discharged from toilets and urinals located within facilities subject
to this subpart.
(ff) The term sediment toxicity as applied to BAT effluent
limitations and NSPS for drilling fluids and drill cuttings shall refer
to ASTM E1367-92: Standard Guide for Conducting 10-day Static Sediment
Toxicity Tests with Marine and Estuarine Amphipods (Available from the
American Society for Testing and Materials, 100 Barr Harbor Drive, West
Conshohocken, PA, 19428) supplemented with the sediment preparation
procedure in appendix 3 of 40 CFR part 435, subpart A.
(gg) The term static sheen test shall refer to the standard test
procedure that has been developed for this industrial subcategory for
the purpose of demonstrating compliance with the requirement of no
discharge of free oil. The methodology for performing the static sheen
test is presented in appendix 1 to 40 CFR part 435, subpart A.
(hh) The term synthetic material as applied to synthetic-based
drilling fluid means material produced by the reaction of specific
purified chemical feedstock, as opposed to the traditional base fluids
such as diesel and mineral oil which are derived from crude oil solely
through physical separation processes. Physical separation processes
include fractionation and distillation and/or minor chemical reactions
such as cracking and hydro processing. Since they are synthesized by
the reaction of purified compounds, synthetic materials suitable for
use in drilling fluids are typically free of polycyclic aromatic
hydrocarbons (PAH's) but are sometimes found to contain levels of PAH
up to 0.001 weight percent PAH expressed as phenanthrene. Poly(alpha
olefins) and vegetable esters are two examples of synthetic materials
suitable for use by the oil and gas extraction industry in formulating
drilling fluids. Poly(alpha olefins) are synthesized from the
polymerization (dimerization, trimerization, tetramerization, and
higher oligomerization) of purified straight-chain hydrocarbons such as
C6-C14 alpha olefins. Vegetable esters are
synthesized from the acid-catalyzed esterification of vegetable fatty
acids with various alcohols. The mention of
[[Page 5552]]
these two branches of synthetic fluid base materials is to provide
examples, and is not meant to exclude other synthetic materials that
are either in current use or may be used in the future. A synthetic-
based drilling fluid may include a combination of synthetic materials.
(ii) The term SPP toxicity as applied to BAT effluent limitations
and NSPS for drilling fluids and drill cuttings shall refer to the
bioassay test procedure presented in appendix 2 of 40 CFR part 435,
subpart A.
(jj) The term well completion fluids shall refer to salt solutions,
weighted brines, polymers, and various additives used to prevent damage
to the well bore during operations which prepare the drilled well for
hydrocarbon production.
(kk) The term well treatment fluids shall refer to any fluid used
to restore or improve productivity by chemically or physically altering
hydrocarbon-bearing strata after a well has been drilled.
(ll) The term workover fluids shall refer to salt solutions,
weighted brines, polymers, or other specialty additives used in a
producing well to allow for maintenance, repair or abandonment
procedures.
(mm) The term 10-day LC50 shall refer to the
concentration (milligrams/kilogram dry sediment) of the base fluid in
sediment that is lethal to 50 percent of the test organisms exposed to
that concentration of the base fluids after 10-days of constant
exposure.
(nn) The term 10-day LC50 of stock base fluid minus 10-
day LC50 of C16-C18 internal olefin
shall not be less than zero shall mean that the 10-day LC50
of any single sample of the base fluid shall not be less than the
LC50 of C16-C18 internal olefin as a
control standard.
(oo) The term 96-hour LC50 shall refer to the
concentration (parts per million) or percent of the suspended
particulate phase (SPP) from a sample that is lethal to 50 percent of
the test organisms exposed to that concentration of the SPP after 96
hours of constant exposure.
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).
* * * * *
BPT Effluent Limitations--Oil and Grease
[In milligrams per liter]
----------------------------------------------------------------------------------------------------------------
Residual
Average of values for 30 chlorine
Pollutant parameter waste source Maximum for any 1 day consecutive days shall not minimum for
exceed any 1 day
----------------------------------------------------------------------------------------------------------------
* * * * * *
*
Water-Based:
Drilling fluid.............. (\1\)......................... (\1\)......................... NA
Drill cuttings.............. (\1\)......................... (\1\)......................... NA
Non-aqueous:
Drilling fluid.............. 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
the entry for ``Drilling fluids, drill cuttings, and dewatering
effluent'' and by revising footnote 4 and adding footnotes 5-9 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
----------------------------------------------------------------------------------------------------------------
Stream Pollutant parameter BAT effluent limitations
----------------------------------------------------------------------------------------------------------------
* * * * * *
*
Drilling Fluids, Drill Cuttings,
and Dewatering Effluent:\1\
* * * * * *
*
(B) Cook Inlet:
Water-based drilling fluids, SPP Toxicity............... Minimum 96-hour LC50 of the SPP shall be 3
drill cuttings and dewatering percent by volume.\4\
effluent.
Free Oil \2\............... No discharge.
Diesel Oil................. No discharge.
Mercury.................... 1 mg/kg dry weight maximum in the stock
barite.
Cadmium.................... 3 mg/kg dry weight maximum in the stock
barite.
[[Page 5553]]
Non-aqueous drilling fluids and ........................... No discharge.
dewatering effluent.
Cuttings associated with non-
aqueous drilling fluids
Stock Limitations.......... Mercury.................... 1 mg/kg dry weight maximum in the stock
barite.
Cadmium.................... 3 mg/kg dry weight maximum in the stock
barite.
Polynuclear Aromatic Maximum 10 ppm wt. PAH based on phenanthrene/
Hydrocarbons (PAH). wt. of stock base fluid.\5\
Sediment Toxicity.......... 10-day LC50 of stock base fluid minus 10-day
LC50 of C16-C18 internal olefin shall not be
less than zero.\6\
Biodegradation Rate........ Percent stock base fluid degraded at 120 days
minus percent C16-C18 internal olefin
degraded at 120 days shall not be less than
zero.\7\
Discharge Limitations...... Diesel oil................. No discharge.
Formation Oil.............. No discharge.\8\
Base fluid retained on Maximum weighted average for well shall be
cuttings. 10.2 percent.\9\
* * * * * *
*
----------------------------------------------------------------------------------------------------------------
\1\ BAT limitations for dewatering effluent are applicable prospectively. BAT limitations in this rule are not
applicable to discharges of dewatering effluent from reserve pits which as of the effective date of this rule
no longer receive drilling fluids and drill cuttings. Limitations on such discharges shall be determined by
the NPDES permit issuing authority.
\2\ As determined by the static sheen test (see appendix 1 to 40 CFR part 435, subpart A).
* * * * * * *
\4\ As determined by the suspended particulate phase toxicity test (see appendix 2 of 40 CFR part 435, subpart
A).
\5\ As determined by EPA Method 1654A: Polynuclear Aromatic Hydrocarbon Content of Oil by High Performance
Liquid Chromatography with an Ultraviolet Detector 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 (NTIS) (703/605-6000)]
\6\ As determined by ASTM E1367-92: Standard Guide for Conducting 10-day Static Sediment Toxicity Tests with
Marine and Estuarine Amphipods (Incorporated by reference and available from the American Society for Testing
and Materials, 100 Barr Harbor Drive, West Conshohocken, PA, 19428) supplemented with the sediment preparation
procedure in appendix 3 of 40 CFR part 435, subpart A.
\7\ As determined by the biodegradation test (see appendix 4 to 40 CFR part 435, subpart A).
\8\ As determined by the GC/MS baseline and assurance method (see appendix 5 to 40 CFR part 435, subpart A), and
by the RPE method applied to drilling fluid removed from cuttings at primary shale shakers (see appendix 6 to
40 CFR part 435, subpart A).
\9\ Maximum permissible retention of base fluid on wet cuttings averaged over drill intervals using non-aqueous
drilling fluids as determined by retort method (see appendix 7 to 40 CFR part 435, subpart A).
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'' 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).
* * * * *
BCT Effluent Limitations
----------------------------------------------------------------------------------------------------------------
Stream Pollutant parameter BCT effluent limitations
----------------------------------------------------------------------------------------------------------------
* * * * * * *
Drilling Fluids and Drill Cuttings and
Dewatering Effluent:\1\
* * * * * * *
Cook Inlet:
Water-based drilling fluid, drill Free oil............................. No discharge.\2\
cuttings, and dewatering effluent.
Non-aqueous drilling fluids and ..................................... No discharge.
dewatering effluent.
Cuttings associated with non-aqueous Free oil............................. No discharge.\2\
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 to 40 CFR Part 435, Subpart A).
* * * * *
12. In Sec. 435.45 the table is amended by revising entry B under
the entry for ``Drilling fluids, drill cuttings, and dewatering
effluent'' and by revising footnote 4 and adding footnotes 5-9 to read
as follows:
[[Page 5554]]
Sec. 435.45 Standards of performance for new sources (NSPS).
NSPS Effluent Limitations
----------------------------------------------------------------------------------------------------------------
Stream Pollutant parameter NSPS effluent limitations
----------------------------------------------------------------------------------------------------------------
Drilling Fluids, Drill Cuttings and
Dewatering Effluent:\1\
* * * * * * *
(B) Cook Inlet:
Water-based drilling fluids, Free oil................... No discharge \2\
drill cuttings and dewatering
effluent.
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.
SPP Toxicity............... Minimum 96-hour LC50 of the SPP shall be 3% by
volume.\4\
Non-aqueous drilling fluids and ........................... No discharge.
dewatering effluent.
Cuttings associated with non-
aqueous drilling fluids
Stock Limitations.......... Mercury.................... 1 mg/kg dry weight maximum in the stock
barite.
Cadmium.................... 3 mg/kg dry weight maximum in the stock
barite.
Polynuclear Aromatic Maximum 10 ppm wt. PAH based on phenanthrene/
Hydrocarbons (PAH). wt. of stock base fluid.\5\
Sediment Toxicity.......... 10-day LC50 of stock base fluid minus 10-day
LC50 of C16-C18 internal olefin shall not be
less than zero.\6\
Biodegradation Rate........ Percent stock base fluid degraded at 120 days
minus percent C16-C18 internal olefin
degraded at 120 days shall not be less than
zero.\7\
Discharge Limitations...... Diesel oil................. No discharge.
Free oil................... No discharge.\2\
Formation oil.............. No discharge.\8\
Base fluid retained or Maximum weighted average for well shall be
cuttings. 10.2 percent.\9\
* * * * * * *
----------------------------------------------------------------------------------------------------------------
\1\ NSPS limitations for dewatering effluent are applicable prospectively. NSPS limitations in this rule are not
applicable to discharges of dewatering effluent from reserve pits which as of the effective date of this rule
no longer receive drilling fluids and drill cuttings. Limitations on such discharges shall be determined by
the NPDES permit issuing authority.
\2\ As determined by the static sheen test (see appendix 1 to 40 CFR part 435, subpart A).
\6\ * * * * * * *
\4\ As determined by the suspended particulate phase toxicity test (see appendix 2 of 40 CFR part 435, subpart
A).
\5\ As determined by EPA Method 1654A: Polynuclear Aromatic Hydrocarbon Content of Oil by High Performance
Liquid Chromatography with an Ultraviolet Detector 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 (NTIS) (703/605-6000)].
\6\ As determined by ASTM E1367-92: Standard Guide for Conducting 10-day Static Sediment Toxicity Tests with
Marine and Estuarine Amphipods (Incorporated by reference and available from the American Society for Testing
and Materials, 100 Barr Harbor Drive, West Conshohocken, PA, 19428) supplemented with the sediment preparation
procedure in appendix 3 of 40 CFR part 435, subpart A.
\7\ As determined by the biodegradation test (see appendix 4 to 40 CFR part 435, subpart A).
\8\ As determined by the GC/MS baseline and assurance method (see appendix 5 to 40 CFR part 435, subpart A), and
by the RPE method applied to drilling fluid removed from cuttings at primary shale shakers (see appendix 6 to
40 CFR part 435, subpart A).
\9\ Maximum permissible retention of base fluid on wet cuttings averaged over drill intervals using non-aqueous
drilling fluids as determined by retort method (see appendix 7 to 40 CFR part 435, subpart A).
[FR Doc. 99-317 Filed 2-2-99; 8:45 am]
BILLING CODE 6560-50-P