United States
Environmental Protection
Agency
Office of Water
4303
EPA-821 -B-98-021
February 1999
& CD A 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
va
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EPA-821 -B-98-021
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
FEBRUARY 1999
Office of Water
Office of Science and Technology
Engineering and Analysis Division
U.S. Environmental Protection Agency
Washington, D.C. 20460
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TABLE OF CONTENTS
Page
LIST OF FIGURES vii
LIST OF TABLES vii
CHAPTER I: INTRODUCTION
1.0 LEGAL AUTHORITY 1-1
2.0 CLEAN WATER ACT 1-1
2.1 BEST PRACTICABLE CONTROL TECHNOLOGY CURRENTLY
AVAILABLE (BPT) 1-2
2.2 BEST CONVENTIONAL POLLUTANT CONTROL TECHNOLOGY (BCT) . . 1-2
2.3 BEST AVAILABLE TECHNOLOGY ECONOMICALLY ACHIEVABLE (BAT) 1-3
2.4 NEW SOURCE PERFORMANCE STANDARDS (NSPS) 1-4
2.5 PRETREATMENT STANDARDS FOR EXISTING SOURCES (PSES) AND
PRETREATMENT STANDARDS FOR NEW SOURCES (PSNS) 1-4
2.6 BEST MANAGEMENT PRACTICES 1-4
3.0 CWA SECTION 304(m) REQUIREMENTS AND LITIGATION 1-5
4.0 POLLUTION PREVENTION ACT 1-5
5 .0 PRIOR FEDERAL RULEMAKINGS AND OTHER NOTICES 1-6
6.0 CURRENT NPDES PERMIT STATUS I-10
CHAPTER II: PURPOSE AND SUMMARY OF THE PROPOSED REGULATION
1.0 PURPOSE OF THIS RULEMAKING II-l
2.0 SUMMARY OF PROPOSED SBF GUIDELINES II-2
3.0 CORRECTION TO THE REGULATORY LIMIT FOR RETENTION OF BASE FLUID
ON CUTTINGS II-S
4.0 REFERENCES II-l 1
CHAPTER HI: DEFINITION OF SBF AND ASSOCIATED WASTESTREAMS
1.0 INTRODUCTION III-l
2.0 INDUSTRY DEFINITION III-l
3.0 WASTESTREAMS REGULATED BY THE SBF GUIDELINES IH-2
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CHAPTER IV: INDUSTRY DESCRIPTION
1.0 INTRODUCTION IY-1
2.0 DRILLING ACTIVITIES IY-1
2.1 EXPLORATORY DRILLING IV-2
2.1.1 Drilling Rigs IV-2
2.1.2 Formation Evaluation IV-3
2.2 DEVELOPMENT DRILLING IV-4
2.2.1 Well Drilling IV-5
2.3 DRILLING WITH SUB SEA PUMPING IV-8
2.4 TYPES OF DRILLING FLUID IV-9
3.0 INDUSTRY PROFILE: CURRENT AND FUTURE DRILLING ACTIVITIES .... IV-10
3.1 ANNUAL WELL COUNT DATA IV-10
4.0 REFERENCES IV-17
CHAPTER V: DATA AND INFORMATION GATHERING
1.0 INTRODUCTION V-l
1.1 EXPEDITED GUIDELINES APPROACH V-l
1.2 IDENTIFICATION OF INFORMATION NEEDS V-2
2.0 STAKEHOLDERS RESEARCH WORK GROUPS V-3
2.1 FORMATION OIL CONTAMINATION DETERMINATION V-3
2.2 RETENTION ON CUTTINGS V-4
2.3 TOXICITY TESTING V-5
2.4 ENVIRONMENTAL EFFECTS / SEABED SURVEYS V-6
3.0 EPA RESEARCH ON TOXICITY, BIODEGRADATION, AND
BIO ACCUMULATION V-7
4.0 INVESTIGATION OF DRILLING SOLIDS CONTROL TECHNOLOGIES V-9
5.0 ASSISTANCE FROM STATE AND FEDERAL AGENCIES V-10
6.0 ASSISTANCE FROM AMERICAN PETROLEUM INSTITUTE V-ll
7.0 REFERENCES V-12
CHAPTER VI: SELECTION OF POLLUTANT PARAMETERS
1.0 INTRODUCTION YI-1
2.0 STOCK LIMITATIONS OF BASE FLUIDS YI-1
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TABLE OF CONTENTS
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2.1 GENERAL VI-1
2.2 PAH CONTENT \ 1-2
2.3 SEDIMENT TOXICITY \ 1-2
2.4 BIODl'GRADATION \ 1-4
2.5 BIO ACCUMULATION \ 1-5
3.0 DISCHARGE LIMITATIONS \ 1-5
3.1 FREE OIL \ 1-5
3.2 FORMATION OIL CONTAMINATION \ 1-6
3 .3 RETENTION OF SBF ON CUTTINGS \ 1-6
4.0 MAINTENANCE OF CURRENT REQUIREMENTS \ 1-7
5.0 REFERENCES VI-9
CHAPTER VII: DRILLING WASTES CHARACTERIZATION, CONTROL, AND
TREATMENT
1.0 INTRODUCTION YII-1
2.0 DRILLING WASTE SOURCES YII-1
2.1 DRILLING FLUID SOURCES YII-2
2.2 DRILL CUTTINGS SOURCES YII-4
3.0 DRILLING WASTE CHARACTERISTICS YII-6
3.1 DRILLING FLUID CHARACTERISTICS \ II-6
3.2 DRILL CUTTINGS CHARACTERISTICS YII-S
3.3 FORMATION OIL CONTAMINATION VH-9
4.0 DRILLING WASTE VOLUMES VH-9
4.1 FACTORS AFFECTING DRILLING WASTE VOLUMES VH-9
4.2 ESTIMATES OF DRILLING WASTE VOLUME YII-11
4.2.1 Waste SBF/OBF Drill Cuttings Volumes VII-11
4.2.2 Drilling Fluid Retention Values VII-12
4.2.3 Calculation of Model Well Drilling Waste Volumes VII-17
5.0 CONTROL AND TREATMENT TECHNOLOGIES VII-17
5.1 BPT/BCT TECHNOLOGY \ 11-20
5.2 PRODUCT SUBSTITUTION: SBF BASE FLUID SELECTION VII-20
5.2.1 Currently Available Synthetic and Non-Aqueous Base Fluids VII-21
5.2.2 PAH Content of Base Fluids YII-21
5.2.3 Sediment Toxicity of Base Fluids VII-22
5.2.4 Biodegradati on Rate of Base Fluids VII-23
5.2.5 Product Substitution Costs VII-25
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TABLE OF CONTENTS
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5.3 SOLIDS CONTROL: WASTE MINIMIZATION/
POLLUTION PREVENTION \ 11-25
5.3.1 Shale Shakers \ 11-26
5.3.2 Centrifuges VH-31
5.3.3 Screw Presses VH-35
5.4 LAND-BASED TREATMENT AND DISPOSAL \ 11-36
5.4.1 Transportation to Land-Based Facilities VH-36
5.4.2 Land Treatment and Disposal VH-38
5.4.3 Land-Based Surface Injection VH-39
5.5 ONSITE SUBSURFACE INJECTION VH-40
5.6 ADDITIONAL CONTROL METHODOLOGIES CONSIDERED VII-43
6.0 REFERENCES \ 11-44
CHAPTER VHI: COMPLIANCE COST AND POLLUTANT REDUCTION
DETERMINATION OF DRILLING FLUIDS AND DRILL CUTTINGS
1.0 INTRODUCTION \ III-1
2.0 OPTIONS CONSIDERED AND SUMMARY COSTS YIII-1
3.0 COMPLIANCE COST METHODOLOGY YIII-2
3.1 DATA AND ESTIMATES USED TO GENERATE COSTS VIH-2
3.1.1 Drilling Activity VIH-2
3.1.2 Model Well Characteristics VIII-5
3.1.3 Onsite Solids Control Technology Costs VIII-6
3.1.4 Transportation and Onshore Disposal Costs VIII-9
3.1.5 Onsite Grinding and Inj ection Costs VIE-11
3.2 DETAILED ANALYSES OF COMPLIANCE COST OPTIONS VIII-12
3.2.1 Discharge Option Compliance Costs VIII-16
3.2.2 Zero Discharge Option Compliance Costs VIII-20
3.2.3 NSPS Compliance Cost Analysis VIII-22
4.0 POLLUTANT REDUCTIONS YIII-23
4.1 DATA AND ESTIMATES USED TO GENERATE POLLUTANT
REDUCTIONS YIII-23
4.2 INCREMENTAL POLLUTANT REDUCTIONS METHODOLOGY VIII-24
4.2.1 BAT Baseline Pollutant Loadings VIII-25
4.2.2 BAT Discharge Option Pollutant Reductions VIII-25
4.2.3 BAT Zero Discharge Option Pollutant Reductions VIII-28
4.2.4 NSPS Pollutant Reductions Analysis VIII-28
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5.0 BCT COMPLIANCE COSTS AND POLLUTANT REDUCTIONS VIII-28
6.0 REFERENCES YIII-30
CHAPTER IX: NON-WATER QUALITY ENVIRONMENTAL IMPACTS AND OTHER
FACTORS
1.0 INTRODUCTION IX-1
2.0 SUMMARY OF NON-WATER QUALITY ENVIRONMENTAL IMPACTS IX-1
3.0 ENERGY REQUIREMENTS AND AIR EMISSIONS IX-3
3 .1 ENERGY REQUIREMENTS IX-5
3.1.1 Baseline Energy Requirements IX-6
3.1.2 BAT Discharge Option Energy Requirements IX-8
3.1.3 BAT Zero Discharge Option Energy Requirements IX-10
3.2 AIR EMIS SIONS IX-14
3 .3 NSPS ENERGY REQUIREMENTS AND AIR EMISSIONS IX-16
4.0 SOLID WASTE GENERATION IX-19
5.0 CONSUMPTIVE WATER USE IX-19
6.0 OTHER FACTORS IX-21
6.1 IMPACT OF MARINE TRAFFIC IX-21
6.2 SAFETY IX-22
7.0 REFERENCES IX-23
CHAPTER X: OPTIONS SELECTION RATIONALE
1.0 INTRODUCTION X-l
2.0 REGULATORY OPTIONS CONSIDERED FOR SBFs NOT ASSOCIATED WITH
DRILL CUTTINGS X-l
3.0 REGULATORY OPTIONS CONSIDERED FOR SBFs ASSOCIATED WITH DRILL
CUTTINGS X-l
3 .1 BPT TECHNOLOGY OPTIONS CONSIDERED AND SELECTED X-3
3 .2 BCT TECHNOLOGY OPTIONS CONSIDERED AND SELECTED X-4
3.3 BAT TECHNOLOGY OPTIONS CONSIDERED AND SELECTED X-4
3.3.1 Stock Base Fluid Technical Availability and Economic Achievability . . . X-5
3.3.2 Discharge Limitations Technical Availability and Economic Achievability X-6
3.4 NSPS TECHNOLOGY OPTIONS CONSIDERED AND SELECTED X-l 1
3.5 TABLES OF PROPOSED LIMITATIONS X-l 1
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TABLE OF CONTENTS
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4.0 REFERENCES X-15
CHAPTER XI: BEST MANAGEMENT PRACTICES XI-1
GLOSSARY AND ABBREVIATIONS G-l
APPENDIX VII-1: CALCULATION OF DISCHARGED CUTTINGS
COMPOSITION A-l
APPENDIX VIII-1: ZERO DISCHARGE: HAULING AND ONSHORE WASTE
DISPOSAL CALCULATION OF SUPPLY BOAT FREQUENCY A-7
APPENDIX VIII-2: BAT COMPLIANCE COST CALCULATIONS A-13
APPENDIX VHI-3: NSPS COMPLIANCE COST CALCULATIONS A-25
APPENDIX VHI-4: POLLUTANT LOADINGS AND REDUCTIONS
CALCULATIONS A-33
APPENDIX IX-1: BAT NON-WATER QUALITY ENVIRONMENTAL IMPACT
CALCULATIONS FOR EXISTING SOURCES A-53
APPENDIX IX-2: NSPS NON-WATER QUALITY ENVIRONMENTAL IMPACT
CALCULATIONS FOR NEW SOURCES A-79
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LIST OF FIGURES
Page
IV-1 GENERALIZED DRILLING FLUIDS CIRCULATION SYSTEM IV-7
VII-1 GENERALIZED SOLIDS CONTROL SYSTEM \ 11-27
VII-2 SCHEMATIC SIDE AND FRONT VIEWS OF TWO-TIERED
SHALE SHAKERS \ 11-30
VII-3 CONFIGURATION OF AMIRANTE SOLIDS CONTROL EQUIPMENT VII-34
LIST OF TABLES
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IV-1 ESTIMATED NUMBER OF WELLS DRILLED ANNUALLY BY
GEOGRAPHIC AREA IY-11
IV-2 ESTIMATED NUMBER OF WELLS DRILLED ANNUALLY BY
DRILLING FLUID IV-15
VII-1 SBF DRILLING WASTE CHARACTERISTICS YII-7
VII-2 MODEL WELL VOLUME DATA VII-13
VII-3 INPUT DATA AND GENERAL EQUATIONS FOR CALCULATING PER-WELL
WASTE VOLUMES YII-18
VII-4 SUMMARY MODEL WELL WASTE VOLUME ESTIMATES VII-19
VII-5 DRILLING FLUID RECOVERY DEVICES \ 11-32
Vin-1 ANNUAL INCREMENTAL COMPLIANCE COSTS AND POLLUTANT
REDUCTIONS FOR DRILL CUTTINGS BAT AND NSPS OPTIONS VIII-3
VIH-2 SUMMARY ANNUAL BASELINE, COMPLIANCE, AND INCREMENTAL
COMPLIANCE COSTS FOR MANAGEMENT OF SBF-CUTTINGS FROM
EXISTING SOURCES YIII-13
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LIST OF TABLES
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VIII-3 SUMMARY ANNUAL BASELINE, COMPLIANCE, AND INCREMENTAL
COMPLIANCE COSTS FOR MANAGEMENT OF SBF-CUTTINGS FROM NEW
SOURCES Vin-14
Vin-4 ESTIMATED NUMBER OF IN-SCOPE WELLS DRILLED ANNUALLY VIII-15
VIII-5 DETAILED INCREMENTAL BAT DISCHARGE OPTION COMPLIANCE
COSTS Vin-19
VIII-6 SUMMARY ANNUAL POLLUTANT LOADINGS AND INCREMENTAL
REDUCTIONS FOR MANAGEMENT OF SBF CUTTINGS FROM EXISTING
SOURCES VIH-26
VIII-7 SUMMARY ANNUAL POLLUTANT LOADINGS AND INCREMENTAL
REDUCTIONS FOR MANAGEMENT OF SBF CUTTINGS FROM
NEW SOURCES YIII-29
IX-1 SUMMARY ANNUAL NWQEI FOR DRILL CUTTINGS IX-3
IX-2 SUMMARY BAT AIR EMISSIONS AND FUEL USAGE IX-5
IX-3 SUMMARY BAT AIR EMISSIONS IX-16
IX-4 UNCONTROLLED EMISSION FACTORS FOR DRILL CUTTINGS
MANAGEMENT ACTIVITIES IX-17
IX-5 SUMMARY NSPS AIR EMISSIONS AND FUEL USAGE IX-18
IX-6 SOLID WASTE DISPOSED BY ZERO DISCHARGE TECHNOLOGIES FOR
EXISTING AND NEW SOURCES IX-20
X-l PROPOSED BPT AND BCT EFFLUENT LIMITATIONS X-12
X-2 PROPOSED BAT EFFLUENT LIMITATIONS X-l3
X-3 PROPOSED NSPS EFFLUENT LIMITATIONS X-14
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CHAPTER I
INTRODUCTION
1.0 LEGAL AUTHORITY
The Environmental Protection Agency (EPA) is proposing Effluent Limitations
Guidelines and New Source Performance Standards for discharges 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 under the authority of Sections 301, 304 (b), (c), and (e), 306,
307, 308, 402, and 501 of the Clean Water Act (CWA) (the Federal Water Pollution Control
Act); 33 U.S.C. 1311, 1314(b), (c), and (e), 1316, 1317, 1318, 1342, and 1361. The proposed
regulation and supporting technical information is presented in the proceeding chapters of this
document. This chapter describes EPA's legal authority for issuing the rule, as well as
background information on prior regulations and litigation related to this proposal.
2.0 CLEAN WATER ACT
Congress adopted the Clean Water Act (CWA) to "restore and maintain the chemical,
physical, and biological integrity of the Nation's waters" (Section 101(a), 33 U.S.C. 1251(a)). To
achieve this goal, the CWA prohibits the discharge of pollutants into navigable waters except in
compliance with the statute. The Clean Water Act confronts the problem of water pollution on a
number of different fronts. Its primary reliance, however, is on establishing restrictions on the
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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.
2.1 BEST PRACTICABLE CONTROL TECHNOLOGY CURRENTLY AVAILABLE
(BPT)
Effluent limitations guidelines based on BPT apply to discharges of conventional, toxic,
and non-conventional pollutants from existing sources (CWA section 304(b)(1)). 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 § 304(b)(1)(B). Where existing performance is
uniformly inadequate, BPT may be transferred from a different subcategory or category.
2.2 BEST CONVENTIONAL POLLUTANT CONTROL TECHNOLOGY (BCT)
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,
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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).
2.3 BEST AVAILABLE TECHNOLOGY ECONOMICALLY ACHIEVABLE (BAT)
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.
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2.4 NEW SOURCE PERFORMANCE STANDARDS (NSPS)
NSPS are based on the best available demonstrated control technology (BADCT) and
apply to all pollutants (conventional, nonconventional, and toxic)(CWA section 306). 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.
2.5 PRETREATMENT STANDARDS FOR EXISTING SOURCES (PSES) AND
PRETREATMENT STANDARDS FOR NEW SOURCES (PSNS)
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 (CWA section 307(b)). 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.
2.6 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).
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3.0 CWA SECTION 304(m) REQUIREMENTS AND LITIGATION
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 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 take final action on the Guidelines by 2000.
4.0 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.
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According to the PPA, source reduction reduces the generation and release of hazardous
substances, pollutants, wastes, contaminants, or residuals at the source, usually within a process.
The term source reduction "include[s] equipment or technology modifications, process or
procedure modifications, reformulation or redesign of products, substitution of raw materials,
and improvements in housekeeping, maintenance, training or inventory control. The term
'source reduction' does not include any practice which alters the physical, chemical, or biological
characteristics or the volume of a hazardous substance, pollutant, or contaminant through a
process or activity which itself is not integral to or necessary for the production of a product or
the providing of a service." 42 U.S.C. 13102(5). In effect, source reduction means reducing the
amount of a pollutant that enters a waste stream or that is otherwise released into the
environment prior to out-of-process recycling, treatment, or disposal.
In this proposed rule, EPA supports pollution prevention technology by encouraging the
use of synthetic-based drilling fluids (SBFs) based on certain synthetic materials and other
similarly performing materials in place of traditional oil-based drilling fluids (OBFs) 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 (SBF-cuttings). 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.
5.0 PRIOR FEDERAL RULEMAKINGS AND OTHER NOTICES
On March 4, 1993, EPA published final effluent guidelines for the Offshore Subcategory
of the Oil and Gas Extraction Point Source Category (58 FR 12454). The data and information
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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 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.
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In the final rulemaking record 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 alterative 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. Based on industry comments, however, EPA did not think
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.
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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 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 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
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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. This
proposed rule is a result of these efforts.
6.0 CURRENT NPDES PERMIT STATUS
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.
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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
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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 this proposed rule 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 the publication of this proposal.
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CHAPTER II
PURPOSE AND SUMMARY OF THE PROPOSED REGULATION
1.0 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. These proposed limitations apply to discharges or effluent 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).
These proposed regulations present 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 is interested in gathering additional information and data in support
for the final rule.
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2.0
SUMMARY OF PROPOSED SBF GUIDELINES
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.
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EPA intends that these proposed regulations would 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
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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 discharge of organic and toxic components. EPA believes that SBFs separated from drill
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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):
o Maximum PAH content 10 ppm (wt. based on phenanthrene/wt. base fluid).
o Minimum rate of biodegradation (biodegradation equal to or faster than C16 - C18
internal olefin by solid phase test).
o 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:
o No free oil by the static sheen test. (BPT/BCT/NSPS)
o Maximum formation oil contamination (95 percent of representative formation
oils failing 1 percent by volume in drilling fluid). (BAT/NSPS)
o Maximum well-average retention of SBF on cuttings (10.2 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:
o Mercury limitation in stock barite of 1 mg/kg. (BAT/NSPS)
o Cadmium limitation in stock barite of 3 mg/kg. (BAT/NSPS)
o Diesel oil discharge prohibition. (BAT/NSPS)
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¦ EPA may require these additional or alternative controls as part of the discharge option
based on method development and data gathering subsequent to publication of this
proposal:
o Maximum sediment toxicity of drilling fluid at point of discharge (minimum LCS0,
mL drilling fluid/kg dry sediment by 10-day sediment toxicity test or amended
test). (BAT/NSPS)
o Maximum aqueous phase toxicity of drilling fluid at point of discharge (minimum
LC50 by SPP test or amended SPP test). (BAT/NSPS)
o 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:
o 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, 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 of this 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 discharged. Applying EPA's existing sediment
toxicity test to the base fluid as a stock limitation ameliorates these concerns, such that, at this
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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 described in Chapter V
of this document. Therefore, the purpose of this 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
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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 this 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 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 currently discharged.
3.0 CORRECTION TO THE REGULATORY LIMIT FOR RETENTION OF BASE
FLUID ON CUTTINGS
An error was made in the draft statistical analysis of the Gulf of Mexico data of retention
of base fluid on drill cuttings. Correction of this error changes the regulatory limit for retention
of base fluid on cuttings as presented in the preamble to the SBF proposed rule from 10.2 to 9.42
percent.1 Since this error has only recently been identified, EPA did not have sufficient time to
correct this regulatory limitation in the preamble. For consistency with the preamble, this SBF
Development Document also uses the same erroneous values except for in this error notification
section. The purpose of this section is to identify and explain the error of the draft statistical
analysis, and present the final values and corrected limits.
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Cost and loadings calculations presented in this and other SBF technical support
documents are not affected by this correction, because the cost and loadings calculations were
based on the round numbers of 11 percent and 7 percent base fluid on cuttings, respectively, for
current practice and BAT technology.
Specifically, correction of the error has resulted in a reduction in the long term average
and recommended limit for percent retention of drilling fluids on drill cuttings generated by
primary and secondary shale shakers in the Gulf of Mexico. The error that occurred relates to the
length of hole drilled per drill cuttings sample. The regulatory limit of percent retention of base
fluid on drill cuttings is based on a volume weighted average over the sections of the well drilled
with SBFs. This means that each retention value is weighted by the volume of hole, determined
by the length and diameter of the hole associated with that particular cuttings sample. The data
analyzed for the Gulf of Mexico consisted of base fluid retention on cuttings at a specific well
depth. The cuttings samples were taken every few hundred feet or so. The error occurred when
the total depth of the well, in the range of tens of thousands of feet, was used in calculating the
volume represented by the cuttings sample, instead of using the difference in well depth from the
previous cuttings sample, which is in the range of a few hundred feet.
This error has been corrected to give the values presented in this paragraph.2 For primary
shakers the mean percent retention on cutting is 10.5. For secondary shakers the mean percent
retention on cuttings is 14.9 and the 95th percentile (used in calculating the corrected limit) is
18.2. This correction to the volume-weighted average values affects the long term average for the
current practice and discharge option, and the proposed regulatory limit for the retention of base
fluid on cuttings.
The error did not occur when EPA analyzed the North Sea data, which was used to
determine the performance of the vibrating centrifuge (BAT technology). For the vibrating
centrifuge the values remain 5.14 percent for the mean (also called the long-term average) and
7.22 for the 95th percentile (used in calculating the proposed limit).
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EPA estimates that in current practice, 80 percent of the cuttings wastestream comes from
the primary shale shaker and the remaining 20 percent comes from the secondary shale shakers.3
Under the model technology of the discharge option, the cuttings from the primary shale shaker,
or 80 percent of the cuttings, are further treated by the vibrating centrifuge. Applying the
retention values above and the 80/20 split in the cuttings wastestream, the well average percent
base fluid on cuttings is corrected to 11.4 for current practice and 7.09 for BAT technology, and
the recommended limit is corrected to 9.42. These values were calculated as follows:
Long-Term Well Average
Current Practice: 0.80 x 10.5% + 0.20 x 14.9% = 11.4% base fluid on wet cuttings
BAT Technology: 0.80 x 5.14% + 0.20 x 14.9% = 7.09% base fluid on wet cuttings
Recommended Limit
BAT Technology: 0.80 x 7.22% + 0.20 x 18.2% = 9.42% base fluid on wet cuttings
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4.0 REFERENCES
1. Daly, J.M., U.S. EPA, Memorandum to SBF Regulatory Record regarding "Correction to
the Regulatory Limits for Retention of Base Fluid on Cuttings as Presented in the
Preamble to the SBF Proposed Rule from 10.2 to 9.42 Percent," January 29, 1999.
2. White, C.E., U.S. EPA, Memorandum to Daly, J.M., U.S. EPA, regarding "Current
Performance, when using Synthetic-Based Drilling Fluids, for Primary Shakers,
Secondary Shakers, and Vibrating Centrifuge and Model Limits for Percent Retention of
Base Fluids on Cuttings for Secondary Shakers and Vibrating Centrifuge," January 29,
1999.
3. Annis, Max R., "Procedures for Sampling and Testing Cuttings Discharged While
Drilling with Synthetic-Based Muds," prepared for the American Petroleum Institute
(API) ad hoc Retention on Cuttings Work Group under the API Production Effluent
Guidelines Task Force, August 19, 1998.
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CHAPTER III
DEFINITION OF SBF AND ASSOCIATED WASTESTREAMS
1.0 INTRODUCTION
This chapter describes the industry, geographic areas and wastestreams to which this
regulation would apply.
2.0 INDUSTRY DEFINITION
This proposed rule would apply to certain coastal and offshore facilities included in the
following standard industrial classification codes: 1311 - Crude Petroleum and Natural Gas, 1381
- Drilling Oil and Gas Wells, 1382 - Oil and Gas Field Exploration Services, and 1389 - Oil and
Gas Field Services, not classified elsewhere.
This regulation would apply to offshore and coastal facilities located in waters where
drilling wastes are allowed for discharge under the current effluent guidelines at 40 CFR Part
435, Subparts A (Offshore) and D (Coastal). The offshore subcategory of the oil and gas
extraction point source category, as defined in 40 CFR 435.10, is comprised of those structures
involved in exploration, development, and production operations seaward of the inner boundary
of the territorial seas (shoreline). The discharge of drilling waste is allowed within the offshore
subcategory beyond three miles from shore, except in offshore Alaska where there is no three
mile discharge prohibition. The coastal subcategory of the oil and gas extraction point source
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category, as defined in 40 CFR 435.40, is comprised of those facilities involved in exploration,
development, and production operations in waters of the United States landward of the inner
boundary of the territorial seas (shoreline). The only area where discharge of drilling waste is
allowed in the coastal subcategory is in Cook Inlet, Alaska.
To summarize, this regulation is applicable to facilities engaged in the drilling of oil and
gas wells in a) offshore waters greater that three miles from shore, except in Alaska offshore
waters from the shoreline out, and b) the coastal waters of Cook Inlet, Alaska.
3.0 WASTESTREAMS REGULATED BY THE SBF GUIDELINES
This proposed rule would apply to wastes generated when oil and gas wells are drilled
with synthetic-based drilling fluids (SBFs) and other non-aqueous drilling fluids by facilities in
coastal and offshore locations where drilling wastes may be discharged. These wastes include
the drilling fluids themselves, and drill cuttings contaminated with the drilling fluids.
This proposed rule also amends the current effluent guidelines such that the current
guidelines are applicable only to water-based drilling fluids (WBF), while the proposed discharge
requirements would be applicable to all other drilling fluids. To achieve this, EPA proposes to
define WBFs and non-aqueous drilling fluids such that all drilling fluids will fall into one
classification or the other. In this way, all drilling fluids would be controlled by either applying
the current requirements for WBFs or the proposed requirements for non-aqueous drilling fluids.
The definition would be based on the miscibility (solubility) of the base fluid in water. The
proposed definitions for various drilling fluids are as follows:
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.
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
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mineral oil, paraffinic oil, or synthetic material such as olefins and vegetable
esters).
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.
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.
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.
There could be other types of non-aqueous drilling fluids that are not listed in the
definitions above. For example, drilling fluids based on synthetic linear paraffins would be
considered non-aqueous drilling fluids.
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CHAPTER IV
INDUSTRY DESCRIPTION
1.0 INTRODUCTION
This chapter describes the major processes associated with the offshore oil and gas
extraction industry, and presents the current and projected drilling activities for this industry.
2.0 DRILLING ACTIVITIES
There are two types of operations associated with drilling for oil and gas: exploratory and
development. Exploratory drilling includes those operations that involve the drilling of wells to
determine potential hydrocarbon reserves. Development drilling includes those operations that
involve the drilling of production wells, once a hydrocarbon reserve has been discovered and
delineated. Although the rigs used in exploratory and development drilling sometimes differ, the
drilling process is generally the same for both types of drilling operations.
The water depth in which either exploratory and development drilling occurs may
determine the operator's choice of drill rigs and drilling systems, including the type of drilling
fluid. The Minerals Management Service (MMS) and the drilling industry classify wells as
located in either deep water or shallow water, depending on whether drilling is in water depths
greater than 1,000 feet or less than 1,000 feet, respectively.
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2.1 EXPLORATORY DRILLING
Exploration for hydrocarbon-bearing strata consists of several indirect and direct
methods. Indirect methods, such as geological and geophysical surveys, identify the physical and
chemical properties of formations through surface instrumentation. Geological surveys
determine subsurface stratigraphy to identify rock formations that are typically associated with
hydrocarbon bearing formations. Geophysical surveys establish the depth and nature of
subsurface rock formations and identify underground conditions favorable to oil and gas
deposits. There are three types of geophysical surveys: magnetic, gravity, and seismic. These
surveys are conducted from the surface with equipment specially designed for this purpose.
Direct exploratory drilling, however, is the only method to confirm the presence of hydrocarbons
and to determine the quantity of hydrocarbons after the indirect methods have indicated
hydrocarbon potential. Exploratory wells are also referred to as "wildcats."
Exploratory wells may be drilled to shallow or deep footage, depending on the purpose of
the well. Shallow exploratory wells are usually drilled in the initial phases of exploration to
discover the presence of oil and gas reservoirs. Deep exploratory wells are usually drilled to
establish the extent of the oil or gas reservoirs, once they have been discovered. These types of
exploration activities are usually of short duration, involve a small number of wells, and are
conducted from mobile drilling rigs.
2.1.1 Drilling Rigs
Mobile drilling rigs are used to drill exploratory wells because they can be easily moved
from one drilling location to another. These units are self contained and include all equipment
necessary to conduct the drilling operation plus living quarters for the crew. The two basic types
of mobile drilling units are bottom-supported units and floating units. Bottom-supported units
include submersibles and jackups. Floating units include inland barge rigs, semisubmersibles,
drill ships, and ship-shaped barges.1
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Bottom-supported drilling units are typically used in the Gulf of Mexico region when
drilling occurs in shallow waters. Submersibles are barge-mounted drilling rigs that are towed to
the drill site and sunk to the bottom. There are two common types of submersible rigs: posted
barge and bottle-type.
Jackups are barge-mounted drilling rigs that have extendable legs that are retracted during
transport. At the drill site, the legs are extended to the seafloor. As the legs continue to extend,
the barge hull is lifted above the water. Jackup rigs can be used in waters up to 300 feet deep.
There are two basic types of design for jackup rigs: columnar leg and open-truss leg.
Floating drilling units are typically used when drilling occurs in deep waters and at
locations far from shore. Semisubmersible units are able to withstand rough seas with minimal
rolling and pitching tendencies. Semisubmersibles are hull-mounted drilling rigs that float on the
surface of the water when empty. At the drilling site, the hulls are flooded and sunk to a certain
depth below the surface of the water. When the hulls are fully submerged, the unit is stable and
not susceptible to wave motion due to its low center of gravity. The unit is moored with anchors
to the seafloor. There are two types of semisubmersible rigs: bottle-type and column-stabilized.
Drill ships and ship-shaped barges are vessels equipped with drilling rigs that float on the
surface of the water. These vessels maintain position above the drill site by anchors on the
seafloor or the use of propellers mounted fore, aft, and on both sides of the vessel. Drill ships
and ship-shaped barges are susceptible to wave motion since they float on the surface of the
water, and thus are not suitable for use in heavy seas.
2.1.2 Formation Evaluation
The operator constantly evaluates characteristics of the formation during the drilling
process. The evaluation involves measuring properties of the reservoir rock and obtaining
samples of the rock fluids from the formation. Three common evaluation methods are well
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logging, coring, and drill stem testing. Well logging uses instrumentation that is placed in the
wellbore and measures electrical, radioactive, and acoustic properties of the rocks. Coring
consists of extracting rock samples from the formation and characterizing the rocks. Drill stem
testing brings fluids from the formation to the surface for analysis.1
2.2 DEVELOPMENT DRILLING
Development of the oil and gas reservoirs involves drilling of wells into the reservoirs to
initiate hydrocarbon extraction, increase production or replace wells that are not producing on
existing production sites. Development wells tend to be smaller in diameter than exploratory
wells because, since the geological and geophysical properties of the producing formation are
known, drilling difficulties can be anticipated and the number of workovers (remedial
procedures) during drilling minimized.
The two most common types of rigs used in developmental drilling operations are the
platform rig and the mobile offshore drilling unit. Development wells are often drilled from
fixed platforms because once the exploratory drilling has confirmed that an extractable quantity
of hydrocarbons exists, a platform is constructed at that site for drilling and production
operations.
To extract hydrocarbons from the reservoir, several wells are drilled into different parts of
the formation. Since all wells must originate directly below the platform, a special drilling
technique, called "controlled directional drilling," is used to steer the direction of the hole and
penetrate different portions of the reservoir. Directional drilling involves drilling the top part of
the well straight and then directing the wellbore to the desired location in non-vertical directions.
This requires special drilling tools and devices that measure the direction and angle of the hole.
Directional drilling also requires the use of drilling fluids that provide more lubricity to prevent
temperature build up and stuck pipe incidents due to the increased friction on the drill bit and
drill string.
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2.2.1 Well Drilling
The process of preparing the first few hundred feet of a well is referred to as "spudding."
This process consists of extending a large diameter pipe, known as the conductor casing, from a
few hundred feet below the seafloor up to the drilling rig. The conductor casing, which is
approximately two feet in diameter, is either hammered, jetted, or placed into the seafloor
depending on the composition of the seafloor. If the composition of the seafloor is soft, the
conductor casing can be hammered into place or lowered into a hole created by a high-pressure
jet of seawater. In areas where the seafloor is composed of harder material, the casing is placed
in a hole created by rotating a large-diameter drill bit on the seafloor. In all cases, the cuttings or
solids displaced from setting the casing are not brought to the surface and are expended onto the
seafloor.
Rotary drilling is the drilling process used to drill the well. Rotary drilling equipment
uses a drill bit attached to the end of a drill pipe, referred to as the "drill string," which makes a
hole in the ground when rotated. Once the well is spudded and the conductor casing is in place,
the drill string is lowered through the inside of the casing to the bottom of the hole. The bit
rotates and is slowly lowered as the hole is formed. As the hole deepens, the walls of the hole
tend to cave in and widen, so periodically the drill string is lifted out of the hole and casing is
placed into the newly formed portion of the hole to protect the wellbore. This process of drilling
and adding sections of casing is continued until final well depth is reached.
Rotary drilling utilizes a system of circulating drilling fluid to move drill cuttings away
from the bit and out of the borehole. The drilling fluid, or mud, is a mixture of water or
sometimes other base fluids, special clays, and certain minerals and chemicals. The drilling fluid
is pumped downhole through the drill string and is ejected through the nozzles in the drill bit
with great speed and pressure. The jets of fluid lift the cuttings off the bottom of the hole and
away from the bit so that the cuttings do not interfere with the effectiveness of the drill bit. The
drilling fluid is circulated to the surface through the space between the drill string and the casing,
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called the annulus. At the surface, the drill cuttings, silt, sand, and any gases are removed from
the drilling fluid before returning it downhole through the drill string to the bit. The cuttings,
sand, and silt are separated from the drilling fluid by a solids separation process which typically
includes a shale shaker, desilter, and desander, and sometimes centrifuges. Figure IV-1 presents
a schematic flow diagram of a generalized drilling fluid circulation system. Some of the drilling
fluid remains with the cuttings after solids separation. Following solids separation, the cuttings
are disposed in one of three ways, depending on the type of drilling fluid used and the oil content
of the cuttings. The disposal methods, which are described in detail in Chapter VII, are
discharge, transport to shore for land-based disposal, and onsite subsurface injection.
Drilling fluids function to cool and lubricate the bit, stabilize the walls of the borehole,
and maintain equilibrium between the borehole and the formation pressure. The drilling fluid
must exert a higher pressure in the wellbore than exists in the surrounding formation, to prevent
formation fluids (water, oil, and gas) from entering the wellbore which will otherwise migrate
from the formation into the wellbore, and potentially create a blowout. A blowout occurs when
drilling fluids are ejected from the well by subsurface pressure and the well flows uncontrolled.
To prevent well blowouts, high pressure safety valves called blowout preventers (BOPs) are
attached at the top of the well.
Since the formation pressure varies at different depths, the density of the drilling fluid
must be constantly monitored and adjusted to the downhole conditions during each phase of the
drilling project. One purpose of setting casing strings is to accommodate different fluid pressure
requirements at different well depths. Other properties of the drilling fluid, such as lubricity, gel
strength, and viscosity, must also be controlled to satisfy changing drilling conditions. The fluid
must be replaced if the drilling fluid cannot be adjusted to meet the downhole drilling conditions.
This is referred to as a "changeover."
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Drilling Fliid
Naw Make-ip
~rilling Fliids
Fliids+Cuttings
Riids+Cuttings
Separation
System
Drilling Flud
Riids+Cuttings
ToDsposal
Figure IV-1
Generalized Drilling Fluids Circulation Systems
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The solids control system is necessary to maintain constant fluid properties and/or change
them as required by the drilling conditions. The ability to remove drill solids from the drilling
fluid, referred to as "solids removal efficiency," is dependent on the equipment used and the
formation characteristics. High solids content in the drilling fluid, or a low solids removal
efficiency, results in increased drilling torque and drag, increased tendency for stuck pipe,
increased fluid costs, and reduced wellbore stability. Detailed discussion of solids control
systems can be found in Chapter VII. In addition to using solids separation equipment, operators
control the solids content of the drilling fluid by adding fresh drilling fluid or components to the
circulating fluid system to reduce the percentage of solids and to rebuild the desired rheological
properties of the fluid. A disadvantage of dilution is that the portion of the fluid removed, or
displaced, from the circulating system must be stored or disposed. Also, additional quantities of
fluid additives are required to formulate the replacement fluid. Both of these add expenses to the
drilling project.
2.3 DRILLING WITH SUBSEA PUMPING
For use in the relatively new area of deepwater drilling, generally greater than 3,000 feet
of water, EPA is aware of a proprietary innovative technology that is claimed by the developer to
contribute to a number of environmental and cost benefits.2 The technology, referred to as
"subsea pumping," involves pumping the drilling fluid up a pipe separate from the drill string
annulus by means of pumps at or near the seafloor. Rotary drilling methods are generally
performed as described above, with the exception that the drilling fluid is boosted by the pump
near the seafloor. By boosting the drilling fluid, the adverse effects 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 50 percent reduction in the number of casing strings generally required
to line the well wall. Wells are drilled in less time, including less trouble time. The developer of
this technology claims that subsea pumping can significantly improve drilling efficiencies and
thereby reduce the volume of drilling fluid discharged, as well as reduce the non-water quality
effects of fuel use and air emissions. Because fewer casing strings are needed, the hole diameter
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in the upper sections of the well can be smaller, which reduces the amount of cuttings produced.
Also, the well bore will require fewer casing strings of smaller diameter, resulting in a reduction
in steel consumption.
To enable the pumping of drilling fluids and cuttings to the surface, about half of the drill
cuttings, comprising the cuttings larger than approximately one-quarter inch, are separated from
the drilling fluid and discharged at the seafloor since these cuttings cannot reliably be pumped to
the surface. With a currently reported design, the drill cuttings that are separated at the seafloor
are discharged through an eductor hose at the seafloor within a 300-foot radius of the well site.
The drilling fluid, which is boosted at the seafloor and transports the remainder of the drill
cuttings back to the surface, is processed as described in the general rotary drilling methods
presented in section IV.2.2.1. For purposes of monitoring, samples of the drilling fluid can be
taken prior to subsea treatment for separation of the larger cuttings, and transported to the surface
for separation of cuttings in a manner identical to that employed at the seafloor.
2.4 TYPES OF DRILLING FLUID
Water-based drilling fluids (WBFs) are the most commonly used drilling fluids and
perform well enough to be used for most drilling. The upper well sections are drilled with WBF,
and a conversion to OBF will, in general, be made only if cost and technical considerations show
a preference towards OBF. WBFs are not only the least expensive drilling fluids on a per barrel
basis, but in general they are less expensive to use since the resultant drilling wastes can be
discharged onsite provided these wastes pass regulatory requirements.
For certain drilling situations, such as drilling in reactive shales, high angle 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
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wastes, they are either transported to shore for disposal or injected into isolated subsurface
formations at the drill site.
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 is 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 synthetic-based drilling fluids
(SBFs) with these synthetic materials as the base fluid to provide the drilling performance
characteristics of traditional OBFs based on diesel and mineral oil, but with the potential for
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.
3.0 INDUSTRY PROFILE: CURRENT AND FUTURE DRILLING ACTIVITIES
3.1 ANNUAL WELL COUNT DATA
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 three miles from shore (excluding the offshore waters of Alaska which has no
three mile discharge restriction), and the coastal waters of Cook Inlet, Alaska. Drilling is
currently active in three regions in these discharge areas: 1) the offshore waters beyond three
miles from shore in the Gulf of Mexico, 2) offshore waters beyond three miles from shore in
California, and 3) the coastal waters of Cook Inlet, Alaska.
Table IV-1 presents the number of wells drilled in these three areas for 1995 through
1997. EPA used the average of the number of wells drilled over these three years to project the
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TABLE IV-1
ESTIMATED NUMBER OF WELLS DRILLED ANNUALLY BY
GEOGRAPHIC AREA
Data Source"
Shallow W'siler
Deep Wsiler
TOTAL
(<1,000 ft)
(> 1,000 ft)
WILIS
Develop.
Kxplor.
Develop.
Kxplor.
Gulf of Mexico
MMS: 1995
557
314
32
52
955
1996
617
348
42
73
1,080
1997
726
403
69
104
1,302
Average Annual
640
355
48
76
1,119
RRCb
5
3
NA
NA
8
Total for Gulf of Mexico
645
358
48
76
1,127
Offshore California
MMS: 1995
4
0
15
0
19
1996
15
0
16
0
31
1997
14
0
14
0
28
Average Annual
11
0
15
0
26
Coastal Cook Inlet
AOGC: 1995
12
0
0
0
12
1996
5
1
0
0
6
1997
5
2
0
0
7
Average Annual
7
1
0
0
8
Sources:
MMS: Minerals Management Service, Ref. 4
RRC: Railroad Commission of Texas, Ref. 5
AOGC: Alaska Oil and Gas Commission, Ref. 6
Data provided by the RRC did not distinguish between development and exploratory wells. EPA allocated the
estimated 8 wells drilled annually in the Texas offshore area between development and exploratory wells in the same
ratio that the average numbers of shallow water wells are distributed in the Gulf of Mexico MMS data.
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future annual drilling activity in each geographic area. Table IV-1 also separates the wells into
four categories: shallow water development (SWD), shallow water exploratory (SWE), deep
water development (DWD), and deep water exploratory (DWE). EPA used these categories to
identify model well characteristics for the compliance technology analyses described in later
chapters of this document.
Among these three areas, most drilling activity occurs in the Gulf of Mexico. As shown
in Table IV-1, 1,302 wells were drilled in the Gulf of Mexico in 1997, compared to 28 wells
drilled in California and 7 wells drilled in Cook Inlet. In the Gulf of Mexico, over the last few
years, there has been high growth in the number of wells drilled in deep water, defined as water
greater than 1,000 feet deep. For example, in 1995, 84 wells were drilled in deep water,
comprising 8.6 percent of all Gulf of Mexico wells drilled that year. By 1997, that number
increased to 173 wells drilled and comprised over 13 percent of all Gulf of Mexico wells drilled.
The increased activity in deep water increases the usefulness of SBFs. Operators drilling in deep
water 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).3
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. The Western
Gulf Region also is associated with the majority of the current use and discharge of SBF cuttings.
For the federal waters of the Gulf of Mexico, EPA used annual well count data compiled
by the Department of the Interior's Minerals Management Service (MMS).4 The MMS data
include wells drilled in offshore waters greater than 3 miles from shore, for all areas where
drilling is active, except in Texas. The state of Texas has jurisdiction over oil and gas leases
extending seaward three leagues (10.4 miles) instead of three miles. Therefore, EPA requested
and received information from the Railroad Commission of Texas regarding the number of wells
drilled in Texas jurisdiction from three to 10.4 miles from shore. This area is affected by the
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proposed rule, but is not included in the MMS data.
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. The MMS data indicate that
five operators are actively drilling in the California Offshore Continental Shelf (OCS) region.4
As shown in Table IV-1, EPA estimates that an average of 26 development wells and no
exploratory wells are drilled in the California OCS each year.
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. All references to Cook Inlet mean Upper Cook Inlet unless otherwise identified.
There are three operators currently active in Cook Inlet.7 EPA projects eight wells per year will
be drilled in Cook Inlet.6
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 northern-most 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.
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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.8
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.8 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.
Based on the information in Table IV-1, EPA further estimated the numbers of wells
drilled annually using WBF, OBF, and SBF in each geographic area, as presented in Table IV-2.
Following are the assumptions and methods EPA used to estimate the well counts in Table IV-2:
Total Gulf of Mexico WBF/SBF/OBF Wells: For the Gulf of Mexico, EPA estimates
that 80% of the average annual wells are drilled using WBF exclusively (902 wells), 10%
(113 wells) are drilled with SBF, and 10% (112) are drilled with OBF.9
Gulf of Mexico SBF Wells: EPA learned that approximately 75% of all deep water wells
in the Gulf of Mexico are drilled with either SBF or OBF.9 Further, EPA learned that
operators are reluctant to use OBF in deep water operations because of the possibility of
riser disconnect.3 For this reason, EPA determined that in deep water: no OBF wells are
drilled, 75% use SBF, and 25% use WBF exclusively. Thus, EPA estimated that 36 of 48
DWD wells and 57 of 76 DWE wells are drilled with SBF annually. Subtracting the deep
water wells from the 113 SBF wells yielded 20 SBF wells drilled in shallow water. The
distribution of SWD and SWE wells drilled with SBF was made equal to the distribution
of these well types in the total well population (i.e., 64.3% of shallow water wells are
development, 25.1% are exploratory).
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TABLE IV-2
ESTIMATED NUMBER OF WELLS DRILLED ANNUALLY
BY DRILLING FLUID
Drilling l-luitl
Shallow Wilier
(<1.000 11)
Deep Wilier
(> 1.000 fi)
TOTA
L
Will.
s
Develop.
Kxplor.
Develop.
Kxplor.
Gulf of Mexico
Total Wells Drilled Annually
645
358
48
76
1,127
Wells Drilled Using WBF
(80%)
560
311
12
19
902
Wells Drilled Using SBF (10%)
13
7
36
57
113
Wells Drilled Using OBF
(10%)
72
40
0
0
112
Offshore California
Total Wells Drilled Annually
11
0
15
0
26
Wells Drilled Using WBF
10
0
4
0
14
Wells Drilled Using OBF
1
0
11
0
12
Coastal Cook Inlet
Total Wells Drilled Annually
7
1
0
0
8
Wells Drilled Using WBF
6
1
0
0
7
Wells Drilled Using OBF
1
0
0
0
1
Gulf of Mexico OBF Wells: Since EPA estimated that OBFs were not used in the deep
water, all 112 OBF wells in offshore Gulf of Mexico are shallow water wells. The
distribution of SWD and SWE wells drilled with OBF was made equal to the distribution
of these well types in the total well population, as described above for SBF shallow water
wells.
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Offshore California and Coastal Cook Inlet SBF/OBF Wells: EPA learned that no wells
are currently drilled with SBF in offshore California and coastal Cook Inlet.7 Therefore,
all wells drilled in these areas are either WBF or OBF wells. The distribution of OBF
wells drilled in shallow and deep waters was based on the distribution of OBF/SBF wells
in Gulf of Mexico shallow and deep waters, as follows: 13.2% of shallow water wells are
drilled with OBF; 75% of deep water wells are drilled with OBF. All other wells were
assumed to be drilled exclusively with WBF.
WBF Wells: The numbers of WBF wells distributed among the four model well types are
simply the difference between the numbers of SBF/OBF wells and the total well
population for a given model well. These numbers are presented here for completeness,
and do not appear in any further analysis in this document. Also, the top portion of SBF
and OBF wells are drilled with WBF, but this portion of the well is not included in EPA's
analysis.
This proposed rule applies to existing and new sources, as defined in Chapter in. Based
on the well information presented above and expansion of the industry into new lease blocks in
the deep water areas of the Gulf of Mexico, EPA estimated that 5% of SWD and 50% of DWD
wells that use SBFs will be new sources. Industry was unable to provide any more specific
estimates. Thus, of the estimated 13 SWD wells drilled annually with SBF in the Gulf of
Mexico, EPA estimated that one of these will be a new source. Of the estimated 36 DWD wells
drilled annually, EPA estimated that 18 of these will be new sources. Exploratory wells, by
definition, are not new source wells. EPA does not project any new source wells to be drilled in
offshore California or coastal Cook Inlet, Alaska.
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4.0 REFERENCES
1. Baker, Ron, "A Primer of Offshore Operations," Second Edition, Petroleum Extension
Service, University of Texas at Austin, 1985.
2. Confidential Business Information regarding subsea pumping system, 1998.
3. American Petroleum Institute, responses to EPA's "Technical Questions for Oil and Gas
Exploration and Production Industry Representatives," attached to e-mail sent by Mike
Parker, Exxon Company, U.S.A., to Joseph Daly, U.S. EPA, August 7, 1998.
4. U.S. Department of the Interior, Minerals Management Service, Herndon, VA, TIMS
Database, MMS 97-007, 1997.
5. Covington, James C., U.S. EPA, Memorandum regarding well count data from the
Railroad Commission of Texas, June 15, 1998.
6. Daly, Joseph, U.S. EPA, Memorandum regarding "Phone Conversation Regarding
Number of Wells Drilled in Cook Inlet, Alaska," October 23, 1998.
7. Veil, John A., Argonne National Laboratory, Washington, D.C., "Data Summary of
Offshore Drilling Waste Disposal Practices," prepared for the U.S. Environmental
Protection Agency, Engineering and Analysis Division, and the U.S. Department of
Energy, Office of Fossil Energy, November 1998.
8. U.S. Environmental Protection Agency, "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, February 1999.
9. Daly, Joseph, U.S. EPA, Memorandum regarding "October 13, 1998 Teleconference
Regarding SBF Use," October 20, 1998.
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CHAPTER V
DATA AND INFORMATION GATHERING
1.0 INTRODUCTION
This chapter describes the sources and methods EPA used to gather data and information
for the proposed SBF Guidelines. The following sections discuss the expedited guidelines
approach for this rulemaking and EPA's identification of information needs.
1.1 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. The
proposed rule is 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.
Throughout regulatory development, EPA 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 (MMS), the Railroad Commission of Texas (RRC), and research and regulatory bodies
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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 participated in the rulemaking as well.
In order to expedite the rulemaking process, 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 the 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.
1.2 IDENTIFICATION OF INFORMATION NEEDS
As part of the final Coastal Oil and Gas 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. 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. In addition, EPA summarized the information
available from seabed surveys at SBF-cuttings discharge sites.
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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."1'2'3'4 The purpose of these documents was to help direct EPA's and other
stakeholder's research efforts in defining BPT, BAT, BCT, and NSPS, and assist permit
authorities' implementation of CWA Section 403(c) ocean discharge requirements.
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.
2.0 STAKEHOLDERS RESEARCH WORK GROUPS
In order to concentrate efforts on certain technical issues, in May of 1997 industry
stakeholders began 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.5
Industry representatives formed work groups to address these issues. The sections below
describe their work.
2.1 FORMATION OIL CONTAMINATION DETERMINATION
The goal of this work group was to define the monitoring and compliance method to
determine crude oil (or other oil such as mineral oil) contamination of SBF-cuttings. The work
group has issued several reports concerning the static sheen test, and developed two replacement
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tests for formation oil contamination, one based on fluorescence and the other on gas
chromatography with mass spectroscopy detection(GC/MS). The reports on the work group's
findings were prepared in three phases, as described below.
On September 28, 1998, the work group published the Phase I report entitled "Evaluation
of Static Sheen Test for Water-based Muds, Synthetic-based Muds and Enhanced Mineral
Oils."6'7 The conclusions of the report are that the static sheen test is not a good indicator of
crude 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 the Phase II report entitled "Survey of
Monitoring Approaches for the Detection of Oil Contamination in Synthetic-based Drilling
Muds."8 This document lists thirteen methods that the work group considered as a replacement
to the static sheen test. From these thirteen, EPA selected for the proposed regulation 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 the Phase in reports entitled
"Laboratory Evaluation of Static Sheen Replacements: RPE Method,"9 and "Laboratory
Evaluation of Static Sheen Replacements: GC/MS Method."10 These reports provide the
proposed procedures for the methods. The future work of the Analytical Work Group is to
validate these methods.
2.2 RETENTION ON CUTTINGS
The goals of this work group were to determine the SBF retention on cuttings attainable
by 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 and analyzed data from GOM wells on the amount of synthetic base fluid retained
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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."11
To address the second goal of determining the total quantity of SBF discharged, the work
group created a spreadsheet that records information allowing two independent analyses of the
SBF quantity discharged.12 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 analysis 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 due to questions of
accuracy with the mass balance method when downhole losses occur. For this reason, the retort
method is the primary proposed method. 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, or a combination of the two methods.
2.3 TOXICITY TESTING
The goal of this work group was to define the toxicity test for monitoring and compliance
of SBF-cuttings. EPA believes 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 showed that SBF
and synthetic base fluid toxicity are mainly evident in the sedimentary phase.13 When measured
in the suspended particulate phase (SPP) in the current Mysid shrimp toxicity test (40 CFR Part
435, Subpart A, Appendix 2), 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.
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Having shown that an aqueous phase test is unlikely to yield satisfactory results with
SBFs and synthetic 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. Three of these are
10-day acute sediment toxicity tests that use the organisms a) Ampelisca abdita, b) Leptocheirus
plumulosus, and c) Mysidopsis bahia. One of these tests, the MICROTOX test (ASTM
D5660-96), uses inhibition of the luminescent marine bacterium Photobacterium phosphoreum
in vitro. The 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 tested
the variables of 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.
2.4 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.
The work group performed a five-day screening cruise at three offshore oil platforms
where SBFs have 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 included a preliminary evaluation of offshore discharge locations and
determined the areal extent of observable physical, chemical, and biological impact. EPA
intended that this base information would provide a) information relative to the immediate
concerns on impacts, and b) valuable preliminary information for designing future offshore
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assessments.
The study provided preliminary information on cuttings deposition, SBF content of
nearfield marine sediments, 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."14
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.
3.0 EPA RESEARCH ON TOXICITY, BIODEGRADATION, AND
BIO AC CUMULATION
Subsequent to this proposal, EPA plans to compare the relative environmental effects of
SBFs and OBFs in terms of a) sediment and aquatic toxicity, b) biodegradation, and c)
bioaccumulation. The methods development to occur as part of this research, and the resulting
data, are intended to be used in developing the final stock base fluid limitations and SBF
discharge limitations.
The base fluids that EPA will 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. The common feature of these oily
base fluids is that they are immiscible (do not mix) with water, and form drilling fluids that do
not disperse in water.
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The outline of EPA's research plan in terms of goals and considerations is as follows:
Sediment toxicity: EPA 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:
1) Amend the EPA 10-day acute sediment toxicity test for application to SBFs and
base fluids.
2) Determine the LC50 values for the base fluids by this method, potentially for
determination of stock limitations values.
3) 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.
Aqueous phase toxicity: EPA intends to investigate whether any correlation exists
between aqueous phase toxicity to Mysid shrimp and sediment toxicity.
Biodegradation: EPA 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.
Bioaccumulation: EPA 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.
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4.0
INVESTIGATION OF DRILLING SOLIDS CONTROL TECHNOLOGIES
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 a
vibrating centrifuge drilling fluid recovery device heretofore used mainly on North Sea drilling
projects. The device reportedly can produce drill cuttings containing less than six percent by
weight 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."15
EPA contacted numerous vendors of solids control equipment and requested information
on performance and cost of the various solids separation units currently available and used
throughout the offshore industry. The specific vendors and the data they provided are identified
in Chapters VII, VIII, and IX of this Development Document.
For the purpose of evaluating solids control equipment performance, EPA statistically
analyzed drill cuttings discharge data from two sources: the 1997 API Retention-On-Cuttings
Work Group report,11 and the vendor of a vibrating centrifuge technology.16'17 The data reported
the quantity of drilling fluid retained on the cuttings waste streams discharged from primary and
secondary shale shakers, as well as from the vibrating centrifuge. EPA compiled the data and
reported summary statistics.18
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5.0
ASSISTANCE FROM STATE AND FEDERAL AGENCIES
The United States Department of Interior Minerals Management Service (MMS)
maintains a data base of the number of wells drilled in offshore waters under MMS jurisdiction,
i.e., those that are not territorial seas or those that are outside of 3 leagues off Texas and Florida.
Except for offshore Texas and Florida, this data base covers the offshore waters beyond three
miles from the shoreline, which corresponds with the area where drilling wastes are currently
allowed for discharge and so is the same area affected by this proposed rule. MMS supplied EPA
with 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).19 Since Texas jurisdiction over oil and gas leases extends out to 3
leagues, or 10.4 miles, information was requested and received from the Railroad Commission of
Texas regarding the number of wells drilled in Texas territorial seas from 3 miles to 10.4 miles
from shore.20 This is the area in the GOM that is affected by this proposed rule, but not included
in the MMS data. Currently, there is no drilling activity that allows discharge in the offshore
waters of Florida from 3 miles to 3 leagues.
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.21 The Alaska Oil and Gas
Commission provided 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.
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."22
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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."23
6.0 ASSISTANCE FROM I II I AMERICAN PETROLEUM INSTITUTE
In lieu of preparing and distributing a questionnaire to the industry, EPA requested
industry profile information from members of API who are active in the workgroups described
above. EPA submitted a list of questions to API,24 and API provided responses in writing.25
API stated that they surveyed four Gulf of Mexico operators, who collectively represent an
estimated 46% of the offshore wells drilled annually using SBFs, with individual percentages as
follows: Shell 27%; Chevron 9%; Texaco 8%; and Exxon 2%.26 The API responses included the
profile for the four model offshore wells that EPA used as the basis for the technical analyses
presented in this Development Document. EPA is not certain as to whether these 46% of the
offshore wells are statistically representative of all offshore wells using SBFs, but absent
additional information, believes this is adequate for purposes of the rule. EPA also notes that the
API respondents reportedly do not engage in certain practices (e.g., hauling SBF-cuttings to
shore) that operators reported using in the document prepared for DOE by Argonne National
Laboratory.22 Therefore, EPA seeks additional information from all operators using SBFs to be
considered in developing the final rule.
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7.0 REFERENCES
1. Avanti Corporation, "Bioaccumulation of Synthetic-Based Drilling Fluids," prepared for
the U.S. Environmental Protection Agency, contract 68-C5-0035, September 30, 1997.
2. Avanti Corporation, "Biodegradation of Synthetic-Based Drilling Fluids," prepared for
the U.S. Environmental Protection Agency, contract 68-C5-0035, September 30, 1997.
3. Avanti Corporation, "Assessment and Comparison of Available Drilling Waste Data from
Wells Drilled Using Water Based Fluids and Synthetic Based Fluids," prepared for the
U.S. Environmental Protection Agency, contract 68-C5-0035, September 30, 1997.
4. Avanti Corporation, "Seabed Survey Review and Summary," prepared for the U.S.
Environmental Protection Agency, contract 68-C5-0035, September 30, 1997.
5. Daly, Joseph, U.S. EPA, Memorandum regarding "May 8-9, 1997, Meeting in Houston,
Texas-Inception of Industry/Stakeholder Work Groups to Address Issues of Discharges
Associated with Synthetic-Based Drilling Fluids (SBF)," January 14, 1999.
6. Weintritt, D. and R. Benjamin, "Evaluation of Static Sheen Test for Water-Based Muds,
Synthetic-Based Muds, and Enhanced Mineral Oils (Draft)," August 1998, with cover
letter from Robert J. Moran, National Ocean Industries Association, to Joseph M. Daly,
U.S. EPA, September 29, 1998.
7. Daly, Joseph, U.S. EPA, E-mail letter to Roger Claff, API, regarding "Comments on
Static Sheen Report," October 15, 1998.
8. Uhler, A.D. and J.M. Neff, Battelle, "Survey of Monitoring Approaches for the Detection
of Oil Contamination in Synthetic-Based Drilling Muds," prepared for the American
Petroleum Institute, August, 1998, with cover letter from Robert Moran, National Ocean
Industries Association, to Joseph Daly, U.S. EPA, October 21, 1998.
9. Uhler, A.D., J.A. Seavey, and G.S. Durell, Battelle, "Laboratory Evaluation of Static
Sheen Replacements: RPE Method (Final Draft Report)," plus addendum, November 16,
1998, with cover letter from Robert Moran, National Ocean Industries Association, to
Joseph Daly, U.S. EPA, November 16, 1998.
10. Uhler, A.D., J.A. Seavey, and G.S. Durell, Battelle, "Laboratory Evaluation of Static
Sheen Replacements: GC/MS Method (Draft Report)," November 16, 1998, with cover
letter from Robert Moran, National Ocean Industries Association, to Joseph Daly, U.S.
EPA, November 19, 1998.
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11. Annis, Max R., "Retention of Synthetic-Based Drilling Material on Cuttings Discharged
to the Gulf Of Mexico," prepared for the American Petroleum Institute (API) ad hoc
Retention on Cuttings Work Group under the API Production Effluent Guidelines Task
Force, August 29, 1997.
12. Annis, Max R., "Procedures for Sampling and Testing Cuttings Discharged While
Drilling With Synthetic-Based Muds," prepared for the American Petroleum Institute
(API) ad hoc Retention on Cuttings Work Group under the API Production Effluent
Guidelines Task Force, August 19, 1998.
13. Hood, C.A., Baker-Hughes Inteq, Letter to Joseph Daly, U.S. EPA, with unpublished
sediment toxicity data from Baker-Hughes Inteq, July 9, 1997.
14. Continental Shelf Associates, Inc., "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," prepared for the API Health and
Environmental Sciences Department, October 21, 1998.
15. The Pechan-Avanti Group, "Demonstration of the 'Mud 10' Drilling Fluid Recovery
Device at the Amoco Marlin Deepwater Drill Site," August 7, 1998.
16. Daly, Joseph, U.S. EPA, Memorandum regarding "Data Showing the Performance of the
Mud 10 with North Sea Oil Wells," January 14, 1999.
17. Martin, Neil, Enaco PLC, letter to Joseph Daly, U.S. EPA, regarding the MUD 10 Fluid
Recovery Unit, with attached literature and data, July 22, 1997.
18. White, Charles E., and Henry D. Kahn, U.S. EPA, Statistics Analysis Section,
Memorandum to Joseph Daly, U.S. EPA, Energy Branch, regarding "Current
Performance, when using Synthetic-Based Drilling Fluids, for Primary Shakers,
Secondary Shakers, and Vibrating Centrifuge and Model Limits for Percent Retention of
Base Fluids on Cuttings for Secondary Shakers and Vibrating Centrifuge," January 29,
1999.
19. U.S. Department of the Interior, Minerals Management Service, Herndon, VA, TIMS
Database, MMS 97-007, 1997.
20. Covington, James C., U.S. EPA, Memorandum regarding well count data from the
Railroad Commission of Texas, June 15, 1998.
21. Daly, Joseph, U.S. EPA, Memorandum regarding "Phone Conversation Regarding
Number of Wells Drilled in Cook Inlet, Alaska," October 23, 1998.
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22. Veil, John A., Argonne National Laboratory, Washington, D.C., "Data Summary of
Offshore Drilling Waste Disposal Practices," prepared for the U.S. Environmental
Protection Agency, Engineering and Analysis Division, and the U.S. Department of
Energy, Office of Fossil Energy, November 1998.
23. Meinhold, Anne, "Framework for a Comparative Environmental Assessment of Drilling
Fluids," prepared for the U.S. Department of Energy, National Petroleum Technology
Office, November 1998.
24. Daly, Joseph, U.S. EPA, letter to Larry Henry, Chevron USA Production Co., regarding
"Technical Questions for Oil and Gas Exploration and Production Industry
Representatives," with attachment, April 1, 1998.
25. American Petroleum Institute, responses to EPA's "Technical Questions for Oil and Gas
Exploration and Production Industry Representatives," attached to e-mail sent by Mike
Parker, Exxon Company, U.S.A., to Joseph Daly, U.S. EPA, August 7, 1998.
26. Daly, Joseph, U.S. EPA, Memorandum regarding "Market Share of Respondents to
Technical Questions, August 17, 1998.
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CHAPTER VI
SELECTION OF POLLUTANT PARAMETERS
1.0 INTRODUCTION
This section presents information concerning the selection of the pollutants to be limited
for the proposed SBF Effluent Limitations Guidelines and Standards. The information consists
of identifying the pollutants for which limitations and standards are proposed. The discussion is
presented in terms of the pollutant parameters associated with either the stock base fluids that are
used to formulate the SBFs, or the drilling fluids and cuttings at the point of discharge.
2.0 STOCK LIMITATIONS OF BASE FLUIDS
2.1 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 poly aromatic hydrocarbon (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
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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.
2.2 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% PAH in
diesel oil and 0.35% PAH in mineral oil.1 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.2 Thus, this stock
limitation would be one component of a rule reflecting the use of the best available technology.
2.3 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.3 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.2 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.4'5'6 The 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-
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92) using a natural sediment and Leptocheirusplumulosus 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 this 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 the
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 suspended particulate phase (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.7 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
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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 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.
2.4 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 base fluids vary widely in
biodegradation rate, as measured by the solid phase test and simulated seabed tests.8 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 (see Table 9-2 in the Environmental
Assessment).9 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 publication of this proposed rule and before the final rule.
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2.5 BIO ACCUMULATION
While not a part of this 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 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.
3.0 DISCHARGE LIMITATIONS
3 .1 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
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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 this 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.
3.2 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.10 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.
3.3 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
VI-6
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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.2
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.
The 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.11 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.
4.0 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 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.2
VI-7
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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% by volume
PAHs, which constitute the more toxic components of petroleum products.
VI-8
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5.0
REFERENCES
1. Daly, Joseph, U.S. EPA, Memorandum regarding "Meeting with Oil and Gas Industry
Representatives Regarding Synthetic Drilling Fluids," July 2, 1996, with two
attachments: 1) Information package entitled "Enhanced Mineral Oils (EMO) for
Drilling," presented by Exxon Co., U.S.A Marketing, Donald F. Jacques, Ph. D., June 25,
1996, and 2) Letter from Michael E. Parker, P.E., Exxon Company U.S.A., to M. B.
Rubin, U.S. EPA, September 17, 1996.
2. U.S. Environmental Protection Agency, Development Document for Effluent Limitations
Guidelines and New Source Performance Standards for the Offshore Subcategory of the
Oil and Gas Extraction Point Source Category, Final, EPA 821-R-93-003, January 1993.
3. Vik, E.A., S. Dempsey and B. Nesgard, "Evaluation of Available Test Results from
Environmental Studies of Synthetic Based Drilling Muds," OLF Project Acceptance
Criteria for Drilling Fluids, Aquateam Report No. 96-010, July 29, 1996.
4. Still, I. and J. Candler, "Benthic Toxicity Testing of Oil-Based and Synthetic-Based
Drilling Fluids," Eighth International Symposium on Toxicity Assessment, Perth,
Western Australia, May 25-30, 1997.
5. Hood, C.A., Baker-Hughes Inteq, Letter to Joseph Daly, U.S. EPA, with unpublished
sediment toxicity data from Baker-Hughes Inteq, July 9, 1997.
6. Candler, J., R. Herbert and A.J.J. Leuterman, "Effectiveness of a 10-day ASTM
Amphipod Sediment Test to Screen Drilling Mud Base Fluids for Benthic Toxicity," SPE
37890, Society of Petroleum Engineers Inc., March 1997.
7. Rabke, S., et al., "Interlaboratory Comparison of 96-hour Mysidopsis bahia Bioassay
Using a Water Insoluble Synthetic-Based Drilling Fluid," presented at the 19th Annual
Meeting of the Society of Environmental Toxicology and Chemistry, Charlotte, NC,
1998.
8. Munro, P.D., C.F. Moffet, L. Couper, N.A. Brown, B. Croce, and R.M. Stagg,
"Degradation of Synthetic Mud Base Fluids in a Solid-Phase Test System," the Scottish
Office of Agriculture and Fisheries Department, Fisheries Research Services Report No.
1/97, January 1997.
9. U.S. EPA, 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, February 1999.
VI-9
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10. Uhler, A.D., J.A. Seavey, and G.S. Durell, Battelle, "Laboratory Evaluation of Static
Sheen Replacements: RPE Method (Final Draft Report)," plus addendum, November 16,
1998, with cover letter from Robert Moran, National Ocean Industries Association, to
Joseph Daly, U.S. EPA, November 16, 1998.
11. Annis, Max R., "Procedures for Sampling and Testing Cuttings Discharged While
Drilling With Synthetic-Based Muds," prepared for the American Petroleum Institute
(API) ad hoc Retention on Cuttings Work Group under the API Production Effluent
Guidelines Task Force, August 19, 1998.
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CHAPTER VII
DRILLING WASTES CHARACTERIZATION, CONTROL, AND
TREATMENT TECHNOLOGIES
1.0 INTRODUCTION
The first three parts of this chapter describe the sources, characteristics, and volumes of
drilling wastes generated from oil and gas drilling operations that use SBFs. The last part of this
chapter describes the control and treatment technologies currently available to recover SBF from
drill cuttings, which reduce the volume of drilling wastes and the quantities of pollutants
discharged to surface waters.
2.0 DRILLING WASTE SOURCES
Drilling fluids and drill cuttings are the most significant wastestreams from exploratory
and development well drilling operations. EPA proposes limitations for the wastestream of SBF
and associated cuttings, hereafter referred to as SBF-cuttings, generated when SBFs or other non-
aqueous drilling fluids are used. All other wastestreams and drilling fluids have current
applicable limitations that are outside the scope of this rulemaking. The following sections
discuss the sources of SBF and SBF-cuttings in terms of the drilling operations that generate this
wastestream.
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2.1 DRILLING FLUID SOURCES
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 water dispersible drilling fluid
such as a WBF, or 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 including1:
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 of fluid compared to another, e.g.,
rate of penetration, well angle, hole size/casing program options, horizontal
deviation,
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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 logistics and operation support, and
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.1 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 recovery of SBF from drill 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 into small particles, called fines. The fines are not only more
difficult to separate from the drilling fluid, but they also deteriorate the properties of the drilling
fluid. Increased recovery from the cuttings is more problematic for WBFs than with SBFs
because WBFs encourage 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 SBF-cuttings 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.
Environmental impacts can be caused by toxic, conventional, and non-conventional
pollutants in the SBF that adheres to the discharged drill cuttings. The adhered SBF drilling fluid
is mainly composed, on a volumetric basis, of the synthetic material, or more broadly speaking,
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oleaginous (oil-like) material. This oleaginous material may cause hypoxia (reduction in oxygen)
or anoxia in the immediate sediment, depending on currents, temperature, and rate of
biodegradation. Oleaginous materials that 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 that 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.2'3'4 The oleaginous material may also be toxic or bioaccumulate, and it may contain
priority pollutants such as polynuclear aromatic hydrocarbons (PAHs). However, SBF base
fluids typically do not contain PAHs (see discussion of drilling fluid pollutant selection in section
VI.2.0).
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. See section VII.3.1 for the list of
pollutants EPA identified as associated with synthetic drilling fluid.
2.2 DRILL CUTTINGS SOURCES
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 the characteristics required to meet
technical drilling requirements. Various sizes of drill cuttings are separated by the solids
separations equipment, and it is necessary to remove the fines as well as the large cuttings from
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the drilling fluid to maintain the required flow properties (see section VH5.3.4 for discussion of
solids control system design).
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 (i.e., fines). As the drilling fluid returns from
down hole laden with drill cuttings, it normally is first passed through primary shale shakers that
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.
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. Total suspended solids (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 that are
added to modify the viscosity. Because the quantity of TSS is so high and consists of mainly
large particles that settle quickly, discharge of SBF drill cuttings can cause benthic smothering
and/or sediment grain size alteration resulting in potential damage to invertebrate populations
and potential alterations in spawning grounds and feeding habits.
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3.0 DRILLING WASTE CHARACTERISTICS
The wastestream discharged from drilling operations that use SBFs or other non-aqueous
drilling fluids consists of three components: adhering drilling fluid, drill cuttings, and formation
oil. Table VII-1 lists the waste characteristic data for these components that EPA compiled as
the basis for the compliance costs, pollutant reductions, and non-water quality environmental
impacts analyses. The following sections discuss the sources and scope of these characteristics
for each waste component.
3.1 DRILLING FLUID CHARACTERISTICS
Based on per-well data provided by API, EPA assumed a model SBF drilling fluid having
a formulation consisting of 47% by weight synthetic base fluid, 33% solids, and 20% water.5
This formulation represents a 70%/30% ratio of synthetic base fluid to water, typical of
commercially available SBFs.6 Because there are no available data to the contrary, EPA further
assumed that this formulation remains unchanged in the wastestream, although it is likely that the
relative proportions of the three components would be altered in the drilling and solids control
operations.
The synthetic base fluid is one of two sources of the conventional pollutant oil and
grease, as shown in Table VII-1. In lieu of oil and grease concentration data for SBFs, EPA
substituted "total oil" for the oil and grease measurement, assuming that the total amount of
synthetic base fluid (plus formation oil) is equivalent to the total oil content of the wastestream.
A total oil concentration of 190 lbs of synthetic base fluid per bbl of SBF (as shown in Table VII-
1) was calculated based on the SBF formulation described above, and a specific gravity of 0.8
(280 lbs/bbl).7'8
EPA assumed that all solids in the drilling fluid are barite, based on standard formulation
data.6'13 Barite is used to control the density of drilling fluids and is the primary source of toxic
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TABLE VII-1
SBF DRILLING WASTE CHARACTERISTICS
Waste Characteristics
Value
References
SBF formulation
47% synthetic base fluid, 33%
barite, 20% water (by weight)
Calculated from industry data (Ref. 5)
Synthetic base fluid density
280 pounds per barrel
Ref. 7 and 8
Barite density
1,506 pounds per barrel
Ref. 9
SBF drilling fluid density
9.6 pounds per gallon
Calculated from industry data (Ref. 5)
Percent (vol.) formation oil
0.2%
See section VII.3.3
Pollulani ( oncenlralions in Mil-'
(
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metal pollutants. The characteristics of raw barite will determine the concentrations of metals
found in the adhering drilling fluid. In order to control the concentration of heavy metals in
drilling fluids, EPA promulgated regulations requiring that stock barite that meet the maximum
limitations 3 mg/1 for cadmuim and 1 mg/1 for mercury (58 FR 12454, March 4, 1993). Table
VII-1 includes the metals concentration profile for barite.
The barite in the SBF is also one of two sources of the conventional pollutant TSS. The
other source of TSS is drill cuttings, as mentioned above in section VII.2.2. The TSS as barite
concentration of 133 lbs/bbl of SBF listed in Table VH-1 was calculated from the SBF
formulation described above, and a barite density of 1,506 lbs/bbl.9
Applying the densities of the synthetic base fluid, barite, and water to the drilling fluid
formulation described above, EPA calculated a drilling fluid weight of 9.6 lbs/gal (405 lbs/bbl).5
EPA recognizes that this weight is lower than typical SBF weights, which can range from 10 to
17 pounds per gallon.6'14 This lower weight is a result of limiting the model formulation to only
three components. Additional solid compounds are typically present in SBFs that add to the
weight of the fluid, but vary too much in weight fraction and type to be included in EPA
estimates.
3.2 DRILL CUTTINGS CHARACTERISTICS
As described in section VII.2.2, drill cuttings contribute the greatest quantity to the
pollutant loadings in the form of TSS. For the purpose of estimating pollutant reductions, EPA
assumed that the TSS concentration attributable to drill cuttings in the wastestream is based on
the density of the dry weight of cuttings, quoted in the literature as 910 lbs/bbl.9 As explained
later in section VII.4.2.3, the actual concentration of cuttings in the waste stream varies with the
amount of drilling fluid estimated to adhere to the cuttings following treatment. However, the
total amount of cuttings generated per well is always equal to the volume of the hole drilled.
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3.3 FORMATION OIL CONTAMINATION
In addition to the base fluid, formation oil is the second source of oil and grease, and is
the only source of priority pollutant and non-conventional pollutant organics in SBFs. For the
proposed rule, the majority of formation oils would cause failure when present in SBFs at a
concentration of about 0.5%. With this limitation, and based on anecdotal information from the
industry concerning formation oil contamination of drilling fluids15, EPA estimates that, on
average, the adhering drilling fluid in a model SBF-cuttings wastestream will contain 0.2% by
volume formation oil. Since the composition of formation (crude) oil varies widely, diesel oil
was used to model the organic pollutant concentrations associated with 0.2% formation oil
contamination. The organic pollutant concentrations, both priority and non-conventional, were
obtained from analytical data presented in the Offshore Oil and Gas Development Document for
Gulf of Mexico diesel.10 The total oil concentration of 0.59 lbs of formation oil per bbl SBF
shown in Table VII-1 was calculated from the SBF formulation described above, and a specific
gravity of 0.84 (294 lbs/bbl) quoted in the literature for diesel oil.9
4.0 DRILLING WASTE VOLUMES
4.1 FACTORS AFFECTING DRILLING WASTE VOLUMES
The volume of drill cuttings generated depends primarily on the dimensions (depth and
diameter) of the well drilled and on the percent washout. Washout is the enlargement of a drilled
hole due to the sloughing of material from the walls of the hole. The greatest volumes of drill
cuttings are generated during the initial stages of drilling when the borehole diameter is large and
washout tends to be higher. Data gathered by EPA for the Coastal Oil and Gas Rulemaking
effort indicate that while percent washout varies depending on the type of formation being
drilled, it generally decreases with hole depth.16 Continuous and/or intermittent discharges are
normal occurrences in the operation of solids control equipment. Such discharges occur for
periods from less than one hour to 24 hours per day, depending on the type of operation and well
conditions.
VH-9
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The volume of drill cuttings generated also depends on the type of formation being
drilled, the type of bit, and the type of drilling fluid used. Soft formations, especially hydrating
shales, are more susceptible to borehole washout than hard formations. The type of drilling fluid
used can affect the amount of borehole washout and shale sloughing. Intervals drilled with
water-based drilling fluids (WBFs) can experience washout of 100 percent and greater, while
intervals drilled with OBFs or SBFs are typically closer to gage size (wherein washout is zero
percent). A rule-of-thumb value of 5 to 10% washout was recently cited by a Gulf of Mexico
operator for intervals drilled with SBF.17 The type of drill bit determines the characteristics of
the cuttings (particle size). Depending on the formation and the drilling characteristics, the total
volume of drill solids generated will be at least equal to the borehole volume, but is most often
greater due to the breaking up of the compacted formation material.
The amount of drilling fluid that adheres to the cuttings depends on the type and
efficiency of the solids control equipment used, the drill particle size, and the type of drilling
fluid used. The solids control system, described in detail in section VII.5.3.4, is a step-wise
operation designed to remove drill cuttings from the drilling fluid by separating successively
smaller particles. Each separation unit in the system produces a cuttings wastestream of a
particular particle size distribution, and with an amount of adhering drilling fluid that, on
average, is characteristic of that unit. The efficiency of a particular separation unit, as measured
by the amount of drilling fluid retained on the cuttings, is maximized through vigilant operation
and maintenance. Other operating factors, such as whether the drilling platform is stationary or
floating, can also affect drilling fluid retention on cuttings.
Small and fine cuttings have greater surface area and generally retain more drilling fluid
than larger cuttings. Therefore, higher retention values are associated with the solids control
units that generate smaller or fine particle cuttings. Data submitted to EPA for wells drilled with
SBF indicate that retention values are generally lower for the primary separation unit that
produces the larger size cuttings, as compared with the secondary separation unit that produces
smaller cuttings.18'19 As stated in section VII.2.1, cuttings are generally easier to separate from
VII-10
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OBFs or SBFs than WBFs because the drill solids do not disperse and break up into finer
particles to the same extent.
4.2 ESTIMATES OF DRILLING WASTE VOLUMES
Based on the waste characteristics presented above in Table VH-1 and well volume data
supplied by industry operators, EPA calculated drilling waste volumes generated from four
model wells. The following sections present the data and methods EPA used to estimate per-well
volumes of drill cuttings, drilling fluid, and formation oil in the wastestream.
4.2.1 Waste SBF/OBF Drill Cuttings Volumes
EPA developed model well characteristics from information provided by the American
Petroleum Institute (API) for the purpose of estimating costs to comply with, and pollutant
reductions resulting from, the proposed discharge option and the zero-discharge option.1 API
provided well size data for four types of wells currently drilled in the Gulf of Mexico:
development and exploratory wells in both deep water (i.e., greater than or equal to 1,000 feet)
and shallow water (i.e., less than 1,000 feet). The following text, as well as text throughout the
Development Document, 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 provided by API included the length of hole drilled for
successive hole diameters, or intervals.1 API provided data for all intervals drilled per well,
which included intervals drilled with WBF and intervals drilled with SBF. From this, EPA
calculated the gage hole volume for the well intervals that API identified as being drilled with
SBF. To calculate the waste cuttings volume, EPA further estimated, based on information
provided by an industry source17, that the gage hole volume would increase by an average 7.5
percent due to washout. EPA also estimated that the amount of washout incurred using SBF is
the same for intervals drilled with OBF, based on industry source information stating that there is
VII-11
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essentially no difference in the performance of the two drilling fluid types.20 For the four model
wells, EPA determined that the volumes of cuttings generated by these SBF or OBF well
intervals are, in barrels, 565 for SWD, 1,184 for SWE, 855 for DWD, and 1,901 for DWE.
These volumes represent only the rock, sand, and other formation solids drilled from the hole,
and do not include drilling fluid that adheres to the dry cuttings. Table VII-2 presents the data
provided by API, and the hole volumes and total waste cuttings volumes that EPA calculated
based on these data.
4.2.2 Drilling Fluid Retention Values
The amount of drilling fluid that adheres to drill cuttings is measurable by retort analysis.
The published retort method currently used by drilling operators and drilling fluid manufacturing
companies is API's Recommended Practice 13B-2: Field Testing Oil-Based Drilling Fluids,
Appendix B: Oil and Water Content From Cuttings For Percentage Greater Than 10% (API RP
13B-2). This method is designed to measure the relative weights of liquid and solid components
in a sample of wet drill cuttings. A summary description of the method is presented by Annis as
follows18:
In this "Retort Procedure," a known weight of wet cuttings is heated in a retort
chamber to vaporize the liquids contained in the sample. The liquids (synthetic-
based drilling material and water vapors) are then condensed, collected, and
measured in a precision graduated receiver. The API recommended
practice...recommends use of a retort sample cup volume of 50-cm3 + 0.25-cm3...
According to API RP 13B-2, the following measurements are made during the
retort procedure:
VII-12
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TABLE VII-2
MODEL WELL VOLUME DATA3
Model Well
Mole Diiimeler1'
Deplli ln(cr\;il''
(¦igi* Volume
(¦igi* Volume
(»«i}»e Volume plus
(inches)
(feet)
(cu. feet)
(hiirrels)
"\5" n W iishoui
(hiirrels)
SWD
8.5
7,500
2,955
526
565
SWE
12.25
6,000
4,911
873
8.5
2,500
985
175
6
1,500
295
52
6,190
1,101
1,184
DWD
12.25
4,500
3,683
655
8.5
2,000
788
140
4,471
795
855
DWE
17.5
4,500
7,517
1,337
12.25
2,000
1,637
291
8.5
2,000
788
140
2,425
1,768
1,901
Data represent only those intervals API identified as being drilled with SBF.1 Numbers in bold typeface are totals
for the given model well.
bSource: API responses to EPA Technical Questions.1
A Weight (API PR 13B-2 uses mass in grams) of the
clean and dry retort assembly (cup, lid, and retort
body with steel wool).
B Weight of the retort assembly and wet cuttings
sample.
C Weight of the clean and dry liquid receiver.
D Weight of the receiver and its liquid contents
(synthetic-based drilling material and water).
E Weight of the cooled retort assembly without the
condenser.
V Volume of water recovered from cooled liquid
receiver.
To calculate the weight % of synthetic-based drilling material on the discharged
cuttings perform the following calculations:
VII-13
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1. Weight of the wet cuttings sample (Mw) equals the weight
of the retort assembly and wet cuttings sample (B) minus
the weight of the clean and dry retort assembly (A).
Mw = B - A
2. Weight of the dry retorted cuttings (Md) equals the weight
of the cooled retort assembly (E) minus the weight of the
clean and dry retort assembly (A).
Md = E - A
3. Weight of the synthetic-based drilling material (M0) equals
the weight of the liquids receiver with its contents (D)
minus the sum of the weight of the dry receiver (C) and the
weight of the water (V). Assume the density of water is 1
g/cm3 the weight of the water is equivalent to the volume of
water.
M0 = D - (C + V)
The sum of Md, M0, and V should be within 5 percent of the weight of the wet
sample (Mw). If it is not, the procedure should be repeated.
API has recently reviewed the method in API RP 13B-2 with the intention of
standardizing the sampling, testing, and recording procedures for determining the retention of
synthetic base fluid on cuttings.21 In addition to the above retort measurements and calculations,
the new procedures include guidelines for sampling, and a worksheet for calculating the amounts
of total waste and waste components generated. API's goal in writing the new procedures is to
"develop a definitive data base on retention of synthetic material in cuttings discharge streams."21
EPA determined average drilling fluid retention values for solids control equipment
currently used in most offshore drilling operations in the U.S., hereafter referred to as baseline
solids control, and for solids control equipment currently used in North Sea drilling operations
capable of achieving retention values consistently lower than baseline solids control, hereafter
referred to as add-on solids control technology. API provided a database of well-specific
retention data for baseline solids control equipment, compiled from service companies that
VII-14
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supply offshore operators with synthetic-based drilling fluid.18 This database contains the results
of retort analyses of SBF-cuttings discarded from what the report calls primary shale shakers,
secondary shale shakers, and centrifuges. Other than these labels for the equipment, the database
provides no further information regarding the arrangement of the solids control systems
associated with the individual wells. While a primary shale shaker can be assumed to be the first
unit in the solids control train, the location and purpose of a what the database calls a
"secondary" shale shaker is ambiguous without additional information. A "secondary" unit
could receive either the drilling fluid or the drill cuttings that exit the primary shakers. Because
the database retention values of the cuttings from the secondary shale shakers are, on average,
higher than those from the primary shakers, EPA assumed that the secondary shakers received
and treated the drilling fluid rather than the cuttings from the primary shakers. The centrifuge
data were too limited to utilize in EPA's analysis. Based on the API database, EPA calculated a
long-term average retention value, weighted by hole volume, of 10.6% by weight of synthetic
base fluid on wet cuttings for a primary shale shaker, and 15.0% for a secondary shale shaker.19
Due to EPA's assumption that SBF and OBF performance is equivalent, these retention values
apply equally to SBF-cuttings and OBF-cuttings in the baseline analysis.
Retention data for the add-on solids control technology were provided by the
manufacturer of a vibrating centrifuge currently used by operators located in the North Sea to
recover SBF from the SBF-cuttings that exit the primary shale shaker.22 Based on these data,
EPA calculated a long-term average retention value, weighted by hole volume, of 5.14% by
weight of synthetic base fluid on cuttings for the vibrating centrifuge. The data show that the
vibrating centrifuge is likely to perform at least as well if not better in the Gulf of Mexico than in
the North Sea. This is because the cuttings entering the vibrating centrifuge already have lower
retention values in the Gulf of Mexico compared to the North Sea. The observed performance
for the primary shale shakers used in series before the vibrating centrifuge was a volume-
weighted average retention of 12.4%.19 This is 1.9 percentage points higher than the average
volume-weighted retention of 10.5% observed for the primary shale shakers in the Gulf of
Mexico. In the North Sea, all cuttings came from primary shale shakers, absent the use of
secondary shale shakers, thereby eliminating the separate wastestream of cuttings from the
VII-15
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secondary shale shakers. Elimination of the finer cuttings from the secondary shale shakers may
also be possible in the Gulf of Mexico. Based on current information, however, EPA assumes
that in Gulf of Mexico operations a portion of the cuttings will be from the secondary shale
shakers.
For the purpose of estimating incremental compliance costs, pollutant reductions, and
non-water quality environmental impacts, EPA calculated weighted average retention values for
the baseline and compliance-level (based on add-on technology) solids control systems. Based
on information provided by API21, EPA estimated that the cuttings from the primary shale shaker
comprise 80% of the cuttings stream, and the remaining 20% is removed by either the secondary
shale shaker or other devices to remove very small cuttings, or fines. Thus, the following
calculation was used to estimate system-wide retention for the baseline solids control system:
Weighted Average Baseline Solids Control Retention: (0.8 x 10.6%) + (0.2 x 15.0%) = 11.5%.
The assumed 80/20 split of the cuttings wastestream was also applied to the compliance-level
solids control system, in which the vibrating centrifuge receives and treats all cuttings from the
primary shale shaker. The weighted average retention for this system is as follows:
Weighted Average Compliance-Level Solids Control Retention: (0.8 x 5.14%) + (0.2 x 15.0%) = 7.11%.
The retention values of 11.5% (wt.) for baseline solids control and 7.11% (wt.) for compliance-
level solids control were rounded to 11% and 7% for all of EPA's cost and pollutant loadings
calculations. This was done because the cost and loadings calculations were performed before all
solids control data could be analyzed in detail. With a simple arithmetic average of these same
data18,22, EPA was able to determine the rounded figures of 11% and 7% retention independent of
the later statistical analysis that resulted in 11.5% and 7.11%.
VII-16
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4.2.3 Calculation of Model Well Drilling Waste Volumes
For each of the four model wells, EPA calculated drilling waste volumes for intervals
drilled with SBF or OBF. The calculations specified per-well volumes for the wastestream
components, including:
dry cuttings (equivalent to gage hole volume plus 7.5% washout),
synthetic base fluid (and oil base fluid in the baseline analysis),
water,
barite,
whole SBF or OBF (the sum of the synthetic or oil base fluid, water, and barite),
formation oil, and
total waste generated (the sum of whole SBF, formation oil, and dry cuttings).
The general approach to this method was to calculate the total waste generated based on the
relative proportions of the above components in the wastestream as defined by the model drilling
fluid formulation, the average drilling fluid retention values, and the assumed 0.2% by volume of
formation oil present in the wastestream. Waste volumes were calculated for each model well
for the two retention values of 11% for the baseline analysis and 7% for the compliance-level
analysis. The input data and generalized equations used for these calculations are shown in Table
VII-3. Appendix VII-1 presents the detailed calculations for the four model wells, based on the
equations in Table VII-3. Table VII-4 presents the summary model well waste volume data that
EPA calculated and used as the basis for the subsequent compliance analyses.
5.0 CONTROL AND TREATMENT TECHNOLOGIES
EPA investigated the technological aspects and costs of four drilling waste management
technologies as potential means of complying with the proposed effluent limitations guidelines,
including:
VII-17
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TABLE VII-3
INPUT DATA AND GENERAL EQUATIONS FOR
CALCULATING PER-WELL WASTE VOLUMES
Input Data and Assumptions
Drilling fluid formulation, wt./wt.: 47% synthetic or oil base fluid, 33% barite, 20% water (Ref. 5)
Densities, converted to pounds per barrel for:
1. synthetic base fluid = 280 lbs/bbl (Ref. 7 and 8)
2. barite = 1,506 lbs/bbl (Ref. 9)
3. water = 350 lbs/bbl
4. dry cuttings = 910 lbs/bbl (Ref. 9)
5. formation oil (as diesel) = 294 lbs/bbl (Ref. 9)
Retort analysis results, wt./wt.: 11% for standard solids control; 7% for compliance-level solids control (see section
VII.4.2.2)
Dry drill cuttings volume (equivalent to gage hole volume plus washout)
hole volume (ft3) = {length (ft) xnx [diameter (ft)/2]2} x (1 + washout fraction of 0.075) (1)
drill cuttings (bbls) = hole volume (ft3) x 0.1781 bbls/ft3 (2)
drill cuttings (lbs) = drill cuttings (bbls) x 910 lbs/bbl (3)
Waste Components in lbs (algebraic calculation of lbs of waste components in the given drilled interval)
TW = (RF x TW) + {[RF x (WF/SF)] x TW} + {[RF x (BF/SF)] x TW }+ (DF x TW) (4)
(base fluid) + (water) + (barite) + (drill cuttings)
where:
TW = total waste (whole drilling fluid + dry cuttings), in lbs
RF = retort weight fraction of synthetic base fluid, decimal number (e.g., 0.11 or 0.07)
WF = water weight fraction from drilling fluid formulation, decimal number
SF = synthetic base fluid weight fraction from drilling fluid formulation, decimal number
BF = barite weight fraction from drilling fluid formulation, decimal number
DF = drill cuttings weight fraction, calculated as follows:
DF = 1 - {RF x [1 + (WF/SF) + (BF/SF)]} (5)
In order to calculate TW, equations (4) and (5) are first used to calculate DF. Then TW is calculated as follows:
TW = drill cuttings (lbs) / DF (6)
Waste Component Amounts Converted from lbs to bbls
synthetic base fluid (bbls) = [RF x TW (lbs)] / (280 lbs/bbl)
water (bbls) = {[RF x (WF/SF)] x TW (lbs)} / (350 lbs/bbl)
barite (bbls) = {[RF x (BF/SF)] x TW (lbs)} / (1,506 lbs/bbl)
Whole Drilling Fluid Volume
whole SBF volume (bbls) = synthetic base fluid (bbls) + water (bbls) + barite (bbls) (7)
0.2% (vol.) Formation Oil in Whole Mud Discharged
formation oil (bbls) = 0.002 x whole SBF volume (bbls) (8)
VII-18
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product substitution,
solids control equipment,
land-based treatment and disposal, and
onsite subsurface injection.
The following sections discuss EPA's findings regarding the current status of these technologies
as applied to drilling wastes associated with SBFs and OBFs.
5.1 BPT/BCT TECHNOLOGY
EPA is proposing to maintain the current BPT and BCT requirement of no free oil as
determined by the static sheen test. This requirement for drilling fluid wastes was first published
on April 13, 1979 (44 FR 22069). At that time, EPA determined that drilling product
substitution, or the use of more environmentally benign products, combined with onshore
disposal was the best practicable control method available. An example of product substitution
is the use of WBF in place of OBF such that the discharged cuttings would pass the no-free-oil
limit. Since SBF-cuttings are currently discharged in the Gulf of Mexico in compliance with the
static sheen test, industry has shown the ability of SBFs to pass the static sheen test by varying
the SBF formulation. Effluent limitations based on this technology allow no discharge of free oil
in drilling fluids and drill cuttings. As applied to SBFs, this is meant to control the occurrence of
oily sheen on the surface of receiving waters when SBF-cuttings are discharged. The static sheen
test is performed on the SBF that has been removed from the cuttings.
5.2 PRODUCT SUBSTITUTION: SBF BASE FLUID SELECTION
EPA is proposing BAT and NSPS effluent limitations guidelines for three characteristics
of the stock base fluid used in synthetic and other non-aqueous drilling fluids, namely:
polyaromatic hydrocarbon (PAH) content, sediment toxicity, and biodegradation rate. EPA
anticipates that these limitations would be achieved by product substitution of the base fluid.
The following sections discuss the technical achievability of the proposed limitations on stock
VII-20
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base fluids.
5.2.1 Currently Available Synthetic and Non-Aqueous Base Fluids
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 this proposed rule. More recently, the industry has moved
away from using poly alpha olefins, and has begun to use various paraffinic oils, both synthetic
and non-synthetic. However, at present, EPA does not have sufficient data to perform the
analyses for the newer paraffinic oil base fluids. In this Development 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.23'24'25
5.2.2 PAH Content of Base Fluids
EPA proposes to establish a PAH content limitation of 0.001 percent, or 10 parts per
million (ppm), weight percent PAH expressed as phenanthrene, as measured by EPA Method
1654A.26 Producers of several SBF base fluids have reported to EPA that their base fluids are
free of PAHs.27 The base fluids that suppliers have reported are free of PAHs include linear
alpha olefins, vegetable esters, certain enhanced mineral oils, synthetic paraffins, certain non-
synthetic paraffins, and others. Diesel oil typically contains on the order of 5% to 10% PAH and
mineral oil typically contains approximately 0.35% PAH.27
VII-21
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5.2.3 Sediment Toxicity of Base Fluids
EPA is 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 olefins. Based on information available to EPA at this time, the only base fluids that
would attain this limitation are the internal olefins and vegetable esters.
Various researchers have performed toxicity testing of the synthetic base fluids with the
10-day sediment toxicity test (ASTM E1367-92) using a natural sediment and Leptocheirus
plumulosus as the test organism.25'28'29 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 LCS0 of 850, enhanced mineral oil
LC50 of 251, internal olefin LC50 of 2,944, and poly alpha olefin LC50 of 9,636. A higher LCS0
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 LCS0 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.30'31 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 that 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,32 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
VII-22
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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 are not available. If vegetable esters are
found to have significantly 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.
5.2.4 Biodegradation Rate of Base Fluids
EPA proposes a limitation of biodegradation rate for the base fluid, as determined by the
solid phase test33, equal to or faster than the rate of a C16-C18 internal olefin. The proposed
method can be found in Appendix 4 to Subpart A of the proposed amendments to 40 CFR Part
435. With this limitation the base fluids currently available for use include vegetable ester, linear
alpha olefin, internal olefins, and possibly certain linear paraffins. Applying the biodegradation
rate, PAH content and sediment toxicity limitations on stock base fluid, EPA data indicate that
internal olefins and vegetable esters would attain all three limitations.
EPA also investigated an alternative numerical 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 numerical limitation as
additional test results are generated.
As with the sediment toxicity test presented above, due to the lack of data from the
VII-23
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biodegradation test, EPA 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 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.34 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 internal olefins as the basis for the biodegradation rate limitation
instead of vegetable esters for two reasons: technical performance and non-water quality
environmental impacts. SBFs formulated with vegetable esters have higher viscosity, which
makes vegetable ester SBFs more difficult to pump, and may even be impractical for deepwater
drilling due to the cooler temperatures and long drill string inherent in deepwater drilling. The
cooler temperatures further increase viscosity, and the long drill string at this higher viscosity
requires high pump pressures to circulate the SBF. 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.24 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 Chapter IX). If future research shows that vegetable esters have a
VII-24
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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.
5.2.5 Product Substitution Costs
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).24 For comparison, diesel
oil-based drilling fluid costs about $65/bbl, and mineral oil-based drilling fluid costs about
$75/bbl.24 According to industry sources, the SBFs that are most widely used and discharged in
the Gulf of Mexico are based on, in order of use, internal olefins, linear alpha olefins, and
vegetable esters.35 Since the proposed 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.
5.3 SOLIDS CONTROL: WASTE MINIMIZATION/POLLUTION PREVENTION
The function of a solids control system, regardless of the type of drilling fluid in use, is to
separate drill cuttings from the drilling fluid so as to maintain the required flow properties of the
drilling fluid. As stated above in section VII.2.1, drilling fluid properties degrade as the amount
of fine particles in the drilling fluid increases. The solids control equipment can cause an
increase in the amount of fine particle solids in the drilling fluid due to the breakdown of larger
drill cuttings as they pass over and through vibrating screens, centrifuges, and other separation
devices. Therefore, the solids control system is designed and operated to limit the mechanical
destruction of the cuttings while maximizing the removal of undesirable solids from the drilling
fluid.
The type of drilling fluid in use affects the ease with which drill solids can be separated.
Cuttings are generally more difficult to remove from WBFs than SBFs because of the tendency
VII-25
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for solids to disperse in the water phase of the WBFs. The approach to solids control can
therefore be markedly different for WBF systems compared to OBF or SBF systems. Additional
equipment such as hydrocyclones and chemical flocculation units are sometimes employed for
WBFs.16 Such separation steps are generally not necessary when SBFs or OBFs are used for
drilling, and are often avoided because they result in additional losses of drilling fluid with the
discarded solids wastestreams. EPA has also learned that there is no distinguishable difference
in the separability of cuttings from OBF as compared to SBF.20'36
A typical solids control system for SBF/OBF drilling consists of at least some of the
following equipment, depending on the drilling program: primary and secondary shale shakers
which perform the initial separation of drill cuttings from drilling fluid, a "drying" shale shaker
or centrifuge to recover drilling fluid from the cuttings wastestream, a "high-g" shale shaker or
centrifuge to remove fine solids from the drilling fluid stream, and sand traps. Figure VII-1
illustrates the arrangement of primary, secondary, and drying shale shakers in a generalized solids
control system. The following sections describe these unit processes as they are currently
utilized in SBF/OBF drilling.
5.3.1 Shale Shakers
Shale shakers, also called vibrating screens, usually occupy the primary and secondary
positions in the solids control equipment train. The function of the primary shale shaker (often
referred to as the "scalp" shaker) is to remove the largest drill cuttings from the active drilling
fluid system and to protect downstream equipment from unnecessary wear and damage from
abrasion. The primary shale shaker receives cuttings and drilling fluid returned from the well
and separates them into a coarse cuttings wastestream and a drilling fluid stream. The secondary
shale shaker, sometimes referred to as a "mud cleaner," receives the drilling fluid stream from
the primary shaker and removes smaller cuttings and fine particles. The drill cuttings that leave
the primary shale shaker may be further treated by an additional shale shaker, herein referred to
as a "drying" shaker to indicate that it treats cuttings as opposed to the secondary shale shaker
which treats drilling fluid. The drying shaker is used to remove additional drilling fluid from the
waste cuttings before they are discharged, injected, or transported offsite for disposal.
VII-26
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o-
Drilling Fluid Returned to V\fellbore
Drilling Fluid &
Cuttings from
VNfellbore
Primary
Shale Shaker
V\fet Cuttings
"Drying"
Shale Shaker
(Optional)
Drilling Fluid
Drilling
Fluid
Cuttings to
Discharge or
Disposal
Secondai
Shale Shaker
("Mud Cleaner"
n
Fines to Discharge
or Disposal
Drilling Fluid
Active Drilling Fluid
System
Fresh
Drilling Fluid
or Drilling Fluid
Components
Drilling Fluid
Returned to
VNfellbore
Fines from
Sandtrap to
Discharge
Figure VII-1. Generalized Solids Control System
VII-27
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Variables involved in shale shaker design include screen cloth characteristics, type of
motion, position of screen, and arrangement of multiple screens. The Development Document
for the Coastal Oil and Gas rulemaking provides a general discussion of how these variables are
reflected in shale shaker design.16 The application of these variables distinguishes the three types
of shale shakers used with SBF/OBF drilling fluid systems. In general, the factor that
distinguishes primary and secondary solids separation equipment design is the size of the solids
removed by each unit. The primary shale shaker has screens with the lowest mesh (i.e., the least
number of openings per linear inch, giving the largest screen hole size) to separate the largest
cuttings. Secondary and drying shale shakers have finer mesh screens to remove smaller cuttings
and fine particles.
In addition to mesh size, screen shape and orientation vary according to the level of
separation required. Both the shape and orientation of the screen affect the retention time, or the
time the process stream is exposed to the separation unit. A longer retention time on a shale
shaker allows for potentially greater separation of solids from drilling fluid, but also increases the
mechanical degradation of the solids. Flat screens provide the least surface area and retention
time, compared to other designs. Flat screens were the first design used in drilling operations
and continue to be used on primary shale shakers to minimize the amount of time the largest
cuttings are exposed to mechanical degradation. More recent designs feature corrugated screens
that, compared to flat screens, have greater surface area, longer retention times, and greater
capacity.9 Corrugated screens are sometimes used on secondary and drying shale shakers.
Screen orientation also varies as needed, with a "downward" slope for faster conveyance and less
retention time, and an "upward" slope for slower conveyance and more retention time.
The impetus to maximize the amount of valuable OBF and SBF returned to the active
drilling system encouraged the development of "high-g" shale shakers, so named for the higher-
than-standard g-force they apply to the shaker screen. The applied g-force in this type of shaker
can range from 6 to 8.0 Gs, as compared with approximately 2 to 4 Gs for standard shakers.9'37
High-g shakers are sometimes used to remove the finest particles from the drilling fluid in order
to control viscosity. High-g shakers can also be used as drying shakers to retrieve drilling fluid
VII-28
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from the cuttings wastestream. The greater impact force of high-g shakers has both positive and
negative effects: it promotes greater separation of liquid from the solids, but also increases the
mechanical degradation of the solids. The effects of mechanical degradation can be counteracted
with finer mesh screens. Shale shaker manufacturers differ on the best approach to the operation
of high-g shale shakers. One manufacturer notes its field tests have shown that 4 to 5 Gs is the
optimum force for a drying shale shaker because greater g-forces move the cuttings too quickly
over the screen and increase the drilling fluid retained on the cuttings.9 Another manufacturer
claims that high-g dryers (with g-forces of 8 Gs and greater) may be used as primary shale
shakers, secondary shale shakers, or "high performance" mud cleaners.37
EPA recently observed the operation of primary and secondary shale shakers, with both
flat and corrugated screen designs, at an offshore Gulf of Mexico drilling operation that was
using SBF at the time of the site visit.17 The first, or primary units in the solids control train at
this site were four two-tier shale shakers aligned in parallel. The two tiers of each unit worked in
series, with gravity feed of the drilling fluid from the top tier to the bottom tier. The top tier of
these shakers was equipped with screens consisting of four flat panels. As shown in Figure VII-
2, the four top screen panels were tilted at increasing angles toward the discharge end. The
cuttings discarded by the top screens were gravel-like bits and clumps of solid material on the
order of a few millimeters in size, many of which retained the shape imparted by the drill bit.
This shape was cited by the operator as indicative of cuttings generated from an interval of shale
drilled with synthetic or diesel based drilling fluid.17 The downward sloping flat screens also
minimized the mechanical degradation of the cuttings on the top tier. The bottom tier of these
shakers was equipped with a corrugated screen that was slightly (less than 3 degrees) sloped
upward toward the discharge end. The cuttings discarded by the lower screens consisted of
smaller cuttings and finer mud-like solids.
VII-29
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Mud & Cuttings
FromVtellbore
SIDE
Four-Panel Screens
Mud&Smaiief^.
Cuttings
Corrugated Screen
Mud to
Active System
n
Larger
Cuttings
Smaller
Cuttings
FRONT
Figure VII-2.
Schematic Side and Front Views of Two-Tiered Shale Shakers
VII-30
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In addition to the two-tiered shale shakers, EPA observed a high-g shale shaker at this
drill site, equipped with an upward sloping corrugated screen, that received approximately one
third of the drilling fluid stream from the primary shakers.17 The function of this shale shaker
was to remove fine particles from the synthetic drilling fluid to reduce its viscosity. The
manufacturer's literature indicates that the maximum g-force attainable by this equipment is 8.0
G.37 The solids that were discharged from the high-g shaker had a mud-like appearance similar
to the solids discharged from the lower screens of the four parallel shakers, but with even finer
particles.
For comparison purposes, EPA reviewed current literature from three major shale shaker
manufacturers. Table VH-5 lists selected design and operating characteristics of shale shakers
and centrifuges commercially available to U.S. drilling operators. All three manufacturers claim
their shale shakers can reduce the amount of SBF or OBF retained on the cuttings to less than
10% base fluid by weight. In a side comment, one company stated that drilling fluid retention
would likely be higher (approximately 12%) on a floating platform.38 Cost information provided
by these companies indicates that the day rate for shale shakers ranges from $190 to $250, for an
average $213 per day, not including installation or labor (see Table VII-5).
5.3.2 Centrifuges
Centrifuges are used in solids control systems either in place of or in addition to shale
shakers. When used as part of a standard solids control system, centrifuges can increase the
solids removal efficiency by 30 to 40 percent.43 Two centrifuge designs currently in use are
decanting centrifuges and perforated rotor centrifuges. The Coastal Oil and Gas Development
Document presents a detailed description of these centrifuge designs.16
In weighted SBF or OBF applications, centrifuges are used to remove fine solids from
drilling fluid discharged by upstream separation equipment, such as a primary or secondary shale
shaker. Some operators avoid this application, however, citing excessive loss of valuable SBF or
OBF with the fine solids.17
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TABLE VII-5
DRILLING FLUID RECOVERY DEVICES3
M ;i 11 u hill u iv r
l)ex iie Name
l)ex iie l \ pi-
Perl'iii'manie
(\\l " Slil-" Kelenlinn
Reported l>\ ( n.i
(apaeilx
Size
( Ia\\ \l 1. inches)
Max. (i-l-'iinv
Applied In
('linings
Chsi Inl'iirmaliiin
I I'WSS unless iilherxx ise imled)
Shale Shakers
Brandt
(Ref. 9 and 38)
ATL-Dryer
SDW-25
Linear motion shale
shakers
Stationary Rigs: 8-10%
Floating Rigs: 12%
ATL: 8
SDW: 7
tons/hr
ATL: 100x71x57
SDW: 134x78x109
ATL: 4.2
SDW: 7
Day Rate: $200-$250/day
Capital Cost: $30K-$40K
O&M: $50/day
Derrick Equipment
(Ref. 37 and 39)
HI-G Dryer
Linear motion shale
shaker
<10%
Up to 1,200
gal/min
142x71x74
8.0
Day Rate: $225/day
Capital Cost: $47.5K
O&M: $600/week
Swaco
(Ref. 40)
ATL-II
Linear motion shale
shaker
6-8%
500 gal/min
129x63x61
6.25
Day Rate: $190/day
Centrifuges
Broadbent
(Ref. 41)
NAb
Decanting centrifuges
<10%
5.5-27.5
tons/hr
NA
NA
£2MM in 1989 (~$3.8MM)
Mud Recovery
Systems, Ltd. (MRS)
(Ref. 17 and 42)
MUD 6
MUD 10
Vibrating centrifuge
<7%
M-6: 11
M-10: 88
tons/hr
M-6: 59x54x52
M-10: 89x74x67
130
Day Rate for Amoco Demo of
Mud-10: $1200 (incl. one FTEC)
Centrifugal Services,
Inc. (CSI) (Ref. 36)
Centrifugal Dryer
Vertical axis centrifuge
2.5-3%
25
tons/hr
footprint: 96x96
800
Technology not yet commercially
available.
Information presented in this table was either quoted or derived from information provided in company literature or telephone communications with company
representatives.
Not available.
Full-time equivalent.
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A more recent application for large capacity centrifuges is to recover SBF from the larger
drill cuttings. These units are installed in place of the drying shale shaker. Such centrifuges
must be large enough to process all the coarse and smaller cuttings discharged by the primary and
secondary shale shakers. Table VII-5 lists centrifuges manufactured by three companies for use
as drilling fluid recovery devices. The first centrifuge listed is a decanting centrifuge that was
manufactured and marketed in the North Sea until zero discharge became the prominent cuttings
management method for North Sea operators in the early 1990s.41 Solids control systems
installed by this manufacturer were sized to process all the cuttings returning from the well, using
two primary and two secondary centrifuges in parallel. The second and third centrifuges listed in
Table VII-5 represent the newest generation of drilling fluid recovery devices. The "Mud 10"
combines design features from both centrifuge and shale shaker, with an internal rotating cone
that also vibrates, thereby achieving the second lowest reported retention of drilling fluid on
cuttings among the devices EPA reviewed. Unlike the Mud 10 whose internal cone rotates
around a horizontal axis, the "Centrifugal Dryer" features a vertically oriented screen centrifuge
that achieves highest reported g-forces, and the lowest reported retention values.36 At the time
EPA obtained this information, the Centrifugal Dryer was under development and not
commercially available. The Mud 10 was developed by a manufacturer serving North Sea
operators, and has a record of proven performance with wells drilled using SBF.22
EPA observed a demonstration of the Mud 10 drilling fluid recovery device during the
site visit to the offshore SBF drilling operation in the Gulf of Mexico.17 Figure VH-3 illustrates
the arrangement of the solids control equipment at this site. The cuttings discharged from the
four two-tiered shale shakers dropped off the screens into a trough located on the floor at the foot
of the shakers, in which an auger conveyor rotated. The cuttings were conveyed laterally to an
opening in the center of the bottom of the trough, and fell from the opening through a 10-inch
pipe to the inlet of the Mud 10 unit located on the deck immediately below the shale shakers and
trough. The manufacturer's literature gives the dimensions of the Mud 10 as: length 1500 mm
(89 inches) x widthl375 mm (74 inches) x height 1325 mm (67 inches).42 On the drilling rig, the
Mud 10 unit was mounted on a platform, adding two to three feet to its height.
VII-33
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SBF Returned to VNfellbore
SBF & Cutting! From VNfellbore
Primary
Shale
Shakers
'High-G'
Shaker
1/3 SB:
Volum i
SBF
SBF
Fines to
Discharge
23 SBI:
Volum i
V\fet Cuttings
Mud 10
Active Drilling Fluid System -*¦
SBF
Returned
to VNfellbore
Cuttings to
Qscharge
Fresh SBF or Fines from
SBF Components Sandtrapto
Qscharge
Figure VII-3. Configuration of Amirante Solids Control Equipment
VII-34
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The Mud 10 unit was completely enclosed, so the cuttings were not visible as they passed
through this separation step. The manufacturer's literature describes the inner-operation of the
Mud 10 as follows 42:
The system induces a centrifugal force of up to 130 G on all of the drill cuttings
produced from the well separating the oil based mud and sub 200 micron drill
cuttings from the main stream of cuttings...Drill cuttings fall into the inlet pipe
and are fed by gravity to the distribution cone/support disc. The distribution cone
removes the cuttings from the discharge end of the inlet pipe and accelerates and
spreads them evenly onto the inner circumference of the conical wedge wire
screen. The drill cuttings are retained on the inner circumference of the wedge
wire screen by centrifugal force. Linear motion is induced axially into the conical
wedge wire screen thus conveying the retained drill cuttings to the discharge end
of the conical wedge wire screen. The oil based mud is forced through the
apertures in the wedge wire screen by the centrifugal force. The recovered mud
then flows from the discharge point to be collected for secondary treatment.
The Mud 10 can process up to 88 tons per hour, and was handling the full flow of the cuttings
from the two-tiered shakers without problems.17 A sample of the cuttings discharged by the Mud
10 appeared to be considerably drier than those discharged from the two-tiered shakers. The cost
of renting the Mud 10, including one man dedicated to its operation, was $1,200 per day.
5.3.3 Screw Presses
In addition to shale shakers and centrifuges, screw presses have been used to separate
adhering drilling fluid from the bulk cuttings wastestream prior to discharge. Screw presses
generally operate by squeezing the cuttings as they are extruded through the unit, producing a
drilling fluid stream and a compressed mass of cuttings. EPA does not have information
concerning the performance or cost of screw presses. EPA has been told that the screw presses
create brick-like solid chunks of cuttings waste with entrapped drilling fluid. Screw presses are
not widely utilized by U.S. drilling operators for recovering drilling fluid from cuttings.
VII-35
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5.4
LAND-BASED TREATMENT AND DISPOSAL
Since the time of the 1993 Offshore Oil and Gas rulemaking, offshore drilling operators
continue to utilize commercial land-based disposal facilities as the predominant means of
meeting zero discharge requirements for OBF drilling waste. An informal survey of offshore
operators recently showed that 11 of thel4 Gulf of Mexico operators in the survey transport 50%
to 100% of their OBF-cuttings to onshore disposal facilities.44 The remainder of the OBF-
cuttings are injected on site. For SBF-cuttings, the survey indicated that all of the 14 Gulf of
Mexico operators use SBF, with one reporting onshore disposal of all its SBF-cuttings.
For the purpose of estimating costs and environmental impacts associated with
transporting and land-disposing OBF- and SBF-cuttings, EPA reviewed the pertinent
assumptions and data compiled in the Offshore and Coastal Oil and Gas rulemaking efforts, and
updated cost and operating information where available. The following sections present EPA's
most recent findings regarding the transportation, land treatment and disposal, and land-based
subsurface injection of OBF- and SBF-cuttings.
5.4.1 Transportation to Land-Based Facilities
Drill cuttings earmarked for land disposal are first placed in cuttings boxes and
transported from offshore platforms to coastal ports or transfer locations by ocean-going supply
boat. Cuttings boxes in the Gulf of Mexico and California are reusable containers available in
15- and 25-barrel sizes, with footprints ranging from 20 to 40 square feet.45,46'47 EPA used the 25-
barrel box for its estimates in the Offshore Oil and Gas rulemaking, and updated the current per-
box rental rate to $25 per day44'46 for the proposed SBF rulemaking. Cuttings boxes used by
operators in Cook Inlet, Alaska are single-use lined wooden crates measuring 4 feet x 4 feet x 4
feet, with an average eight-barrel capacity and a 1995 purchase price of $125 per box.16
Standard sizes for supply boats that service offshore platforms were reported to be 180
and 220 feet in length, with an estimated deck capacity of 80 or more 25-barrel cuttings
VII-36
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boxes.47'48 EPA estimated a deck capacity of 132 eight-barrel cuttings boxes for Cook Inlet
supply boats, based on 3,300 square feet of deck space 461 and a 25-square foot footprint per
cuttings box (16 ft2 plus a half-foot perimeter clear space). Supply boat rental rates were recently
quoted to range from $7,800 to $9,000 per day, with an industry-wide average of $8,500 per
day.47'48
Information supporting the Offshore Oil and Gas rulemaking stated that a regularly
scheduled supply boat visits a drilling rig approximately every four days.45 This source further
estimated that regularly scheduled supply boats would pick up 12 25-barrel cuttings boxes per
trip because that number equals the average drilling rig capacity for storing cuttings boxes. The
same source document provided additional supply boat information, including average speed
(11.5 miles per hour), and the average distance between the port and drilling rig for Gulf of
Mexico and offshore California (100 miles in both areas), with additional distance estimates
between the rig, coastal transfer stations, and port in the Gulf of Mexico (117 miles and 60 miles,
respectively). One disposal company owns a number of coastal transfer stations in the Gulf of
Mexico where cuttings are moved from operator supply boats to disposal company barges that
take the cuttings to port.44'49'50 The estimate of supply boat distance for Cook Inlet, Alaska was
developed in the Coastal Oil and Gas rulemaking and remains unchanged at 25 miles between
port and rig.16 Estimates for supply boat idling, maneuvering, and loading/unloading time were
adopted without change from the Offshore Oil and Gas rulemaking. Chapters VIE and IX
present the source data and detailed methodology EPA used to apply these estimates in
compliance cost and other pertinent analyses.
In all three geographic areas, drill cuttings are transferred to trucks at the port and hauled
to the land disposal site. Truck capacities were obtained from both dated and new sources.
Trucks serving the Gulf of Mexico have a capacity of 5,000 gallons (119 barrels), according to
the same source document that provided supply boat information for the Offshore Oil and Gas
rulemaking.45 Truck information for offshore California was updated to a capacity of two 25-
barrel cuttings boxes.51 Truck capacity for the Cook Inlet area was presented in the Coastal Oil
and Gas rulemaking and remains unchanged at 22 tons per truckload.52 However, the number of
VII-37
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eight-barrel cuttings boxes in a 22-ton load was reduced from 10 to eight boxes, to reflect the
higher density of cuttings containing 11% by weight adhering OBF (704 lbs/bbl) as compared
with the original estimate that was based on a drilling fluid/cuttings mixture weighing 526
lbs/bbl.16 Estimated trucking distances also vary between geographic areas, as follows: 20 miles
round trip between port and disposal facility in the Gulf of Mexico; 300 miles round trip between
port and disposal facility in California (estimated mileage between Ventura and Bakersfield); and
2,200 miles one way from Kenai, Alaska to a disposal facility in Arlington, Oregon.16 Trucking
costs were estimated for California and Cook Inlet, Alaska, but not for the Gulf of Mexico where
trucking is included in the cost imposed by the disposal facility (see section VII.5.4.2 below).
The trucking rate for California was estimated to be $65 per hour.53 The 1995 trucking rate for
Cook Inlet was $1,800 per truckload, as used in the Coastal guidelines effort.52 Chapters VIII
and IX present the application of these data in the compliance cost and other pertinent analyses.
5.4.2 Land Treatment and Disposal
Centralized commercial land treatment and disposal facilities are generally owned by
independent companies. These facilities receive drilling wastes in vacuum trucks, dump trucks,
cuttings boxes, or barges, from both onshore and offshore drilling operations. Most of these
facilities employ a landfarming technique whereby the wastes are spread over small areas and are
allowed to biodegrade until they become claylike substances that can be stockpiled outside of the
landfarming area. Another common practice at centralized commercial facilities is the
processing of drilling waste into a reusable construction material. This process consists of
dewatering the drilling waste and mixing the solids with binding and solidification agents. The
oil and metals are stabilized within the solids matrix and cannot leach from the solids. The
resulting solids are then used as daily cover at a Class I municipal landfill. Other potential uses
for the stabilized material include use as a base for road construction and levee maintenance.54
The Development Document for the Coastal Oil and Gas rulemaking presents a stepwise
description of the treatment and disposal processes employed by a commercial facility located in
southeast Louisiana.16
VII-38
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EPA determined that existing land disposal facilities in the areas accessible to the Gulf of
Mexico offshore and coastal oil and gas subcategories have 5.5 million barrels annual capacity
available for oil and gas field wastes.10 This is more than sufficient capacity to manage the 202
thousand barrels per year of drilling waste that EPA estimates would go to land-based disposal
facilities in the Gulf of Mexico region under the zero discharge option discussed in Chapters VIII
and IX. Land disposal facilities accessible to California oil and gas operations in the offshore
and coastal subcategories are estimated to have 19.4 million barrels annual capacity.10 The zero
discharge option presented in later chapters includes no additional drilling wastes, above that
currently accounted for, going to land-based disposal facilities in California.
EPA updated current disposal facility costs for the three geographic areas. In the Gulf of
Mexico, current disposal prices range from $9.50 per barrel55 to $10.75 per barrel56 to dispose of
OBF-cuttings. If the drilling operator offloads the waste at a coastal transfer station, the facility
charges an additional $4.75 per barrel for the offloading and transportation of the waste to the
facility.55 For California, EPA calculated a unit disposal cost of $12.32 per barrel, based on a
price of $35 per ton for a disposal facility located near Bakersfield51, and the calculated density of
704 lbs/bbl for cuttings with 11% by weight adhering OBF (see Table VII-4). For drilling waste
generated in coastal Cook Inlet, the unit disposal cost of $500 per eight-barrel cuttings box
($62.50 per barrel) was used in the 1995 Coastal Oil and Gas rulemaking for a disposal facility
located in Arlington, Oregon.57 EPA updated the Oregon disposal cost to 1997 dollars (see
Chapter VIII), and assumed that this unit price includes all additional waste handling fees
imposed by the disposal facility.
5.4.3 Land-Based Subsurface Injection
In addition to land treatment and disposal, land-based disposal facilities use subsurface
injection as a means of disposing drilling wastes, including both drilling fluids and drill cuttings.
One of the two major commercial oilfield waste disposal companies serving the Gulf of Mexico
industry currently operates three injection disposal sites in Texas: Port Arthur, Big Hill (30 miles
from Port Arthur), and one in West Texas.50 These three facilities collectively operate 15
VII-39
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injection wells with an estimated one billion barrel total capacity. This company specializes in
the use of depleted salt domes, or limestones associated with other domes, which allow easy
pumping into the dome for disposal. These sites were located by reviewing drilling records to
see where extensive lost circulation problems occurred, indicating a void. The company claims
that its use of existing underground domes is primarily responsible for the large quantities of
oilfield wastes it has disposed. For example, 15 million barrels of petroleum wastes have been
disposed in the Big Hill site since 1993. This company is working toward expanding its injection
disposal sites into Louisiana and Mississippi.
The unit cost for commercial injection of OBF drilling waste at these Gulf of Mexico
locations is comparable to that of land treatment: $9.50 per barrel for waste containing greater
than 10% oil and grease.50 An additional $3.50 per barrel covers ancillary waste handling and
transport conducted by the disposal company.
5.5 ONSITE SUB SURFACE INJECTION
The interest in and use of onsite injection to dispose of drilling wastes at offshore
platforms has increased since the Offshore Oil and Gas rulemaking in 1993. At that time,
subsurface injection was generally limited to disposal of produced water, with drilling waste
injection still in the early stages of development.10 Since then, interest in injection as an
alternative to hauling drilling wastes to landfills has created a market supported by a growing
number of commercial injection service companies. However, the extent to which offshore
drilling operations currently use onsite injection is difficult to estimate from available
information. A recent informal survey of fourteen Gulf of Mexico drilling operators and four
commercial onsite injection companies provided varied responses regarding this issue.44 Of the
fourteen Gulf of Mexico operators, four reported using onsite injection to dispose of a portion of
their OBF-cuttings. The proportion of OBF-cuttings disposed by injection as reported by the four
operators ranged from 5% to 50%, the remainder of which was hauled to land-based disposal
facilities. In addition, four commercial onsite injection companies reported a total of 66 injection
jobs occurring at offshore Gulf of Mexico sites in the past year. When the survey author
VII-40
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compared an estimated 100 offshore Gulf of Mexico wells drilled with OBF annually with the
reported numbers of onsite injection jobs, the comparison suggested that nearly two-thirds of
OBF wells are disposing of drill cuttings by onsite injection.44 However, as noted by the survey
author, the commercial injection companies also provided estimates of industry-wide use of
injection for OBF-cuttings disposal ranging from 10% to 20%. Given these contrasting
estimates, EPA recognizes a need for additional information and study regarding the current
practice of onsite injection of drilling wastes.
The survey of drilling operators also provided information about injection of OBF-
cuttings in areas other than the Gulf of Mexico.44 In California, two out of the five surveyed
operators use OBF, and both haul OBF-cuttings to shore. One of these operators attempted
injection unsuccessfully, indicating that there is an interest in this technology among offshore
California operators. In Cook Inlet, Alaska, all of the three operators contacted in the survey
stated they inject 100% of their OBF-cuttings. However, one of these operators mentioned that
they recently decided to stop drilling off a particular Cook Inlet platform because the State of
Alaska informed them that injection of OBF drilling wastes "was no longer an option for any
future wells."44 In a separate conversation with the commercial injection company that worked at
this Cook Inlet site, EPA learned that approximately 50,000 barrels of cuttings from four newly
drilled wells were successfully injected through the annulus of a single well.58 The North Slope
area of Alaska was the first active drilling area to engage in large-scale grinding and injection
programs10'16, and continues to lead the industry in this regard. The survey contacted the only
operator actively drilling in the offshore waters of northern Alaska, who reported a volume of
105,000 barrels of drilling waste injected annually.44 This operator injects all of its waste WBF,
WBF-cuttings and OBF-cuttings into a dedicated injection well.
Onsite injection differs from commercial land-based injection because its success
depends on the availability of viable receiving formations and confining zones located at the drill
site, whereas commercial facilities are located at large-capacity receiving formations. In onsite
disposal projects, drilling wastes may be injected into either the annulus of the well being drilled
or a dedicated disposal well. One source estimates that approximately half of the offshore
VII-41
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injection jobs utilize annular injection down the well being drilled while the other half uses other
wells on the same platform for disposal.58 The critical parameters that affect the performance of
any grinding and injection system are: drilled solids particle size, the injectable fluid density and
viscosity, percent solids in the injectable fluid, injection pressure, and the characteristics of the
receiving formation. These parameters and their effect on the design of the grinding and
injection system are discussed in detail in the Development Document for the Coastal Oil and
Gas rulemaking.16
EPA contacted two of the commercial injection companies that serve the offshore Gulf of
Mexico drilling industry for current information regarding the equipment, processes, and prices
for onsite injection of drilling wastes. Both companies use a licensed process originally
developed by ARCO, that includes grinding, slurrification, and pumping the cuttings slurry
downhole.58'59 As an example, one of the companies uses two basic equipment sets to grind and
inject cuttings: the viscosifier system and the slurrification skid.58 The viscosifier system picks
up cuttings coming off the rig shale shaker using an auger or vacuum system, and puts them in a
tank where the viscosity is adjusted to put the cuttings into suspension for pumping. For OBF,
the cuttings are suspended in a polymer. Water, mineral oil, and other material can be used to
adjust the viscosity. A grinding or "shredding" pump is used to reduce particle size to 100
microns. From the viscosifier, a centrifugal pump sends the slurry to the slurrification skid.
There, a tank maintains the slurry and provides suction to a high pressure injection pump. This
company reports that it usually achieves a disposal rate at Gulf of Mexico sites of 2 to 3 barrels
. f o
per minute.
Costs associated with onsite injection have been provided in two forms: as daily rental
rates and as unit costs per barrel of cuttings disposed. The daily rates, generally representing the
equipment and labor associated with the injection system, are similar between the three reporting
companies, including quotes of $2,000 per day44, $2,500 per day58, and $2,500-$3,000 per day60.
One of these companies provided costs for additional equipment, specifically $250 per day for an
auger or $1,200-$ 1,300 per day for a vacuum system to transport the cuttings from the rig shale
shaker to the injection system, plus additional labor at $28-$30 per hour to operate the vacuum
VII-42
-------
system.60 Quotes of unit costs per barrel of cuttings disposed vary widely between sources, from
a low of $3 per barrel to a high of $20 per barrel.44 The costs of onsite injection are dependent on
many variables, including hole size (wherein a larger hole might require additional labor at the
start)58, the type of cuttings transfer equipment selected, and whether any downhole problems are
encountered that might cause delays or changes to the disposal program. It is the issue of
unforeseeable downhole problems that concerns drilling operators, who have noted that any
savings realized through onsite injection are sensitive to the ability to inject.61
5.6 ADDITIONAL CONTROL METHODOLOGIES CONSIDERED
As part of the Offshore Oil and Gas rulemaking, EPA investigated four different thermal
distillation and oxidation processes for the removal of oil from drilling wastes (53 FR 41375,
October 21, 1998). The details of EPA's findings are presented in the Development Document
for the Offshore Oil and Gas rulemaking.10 Although these technologies appeared to be capable
of reducing the oil content in oil-based drilling wastes, EPA rejected them from further
consideration because of difficulties associated with the placement of such equipment at offshore
drilling sites, operation of the equipment, intermediate handling of raw wastes to be processed,
and handling of processed wastes and by-products streams.
EPA notes that interest in thermal distillation technologies persists among onshore
commercial disposal companies as a means of treating drilling waste and recovering valuable
SBF and OBF for reconditioning and reuse.36'40 EPA did not investigate this technology any
further because its application is at land-based rather than offshore facilities.
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6.0 REFERENCES
1. American Petroleum Institute, responses to EPA's "Technical Questions for Oil and Gas
Exploration and Production Industry Representatives," attached to e-mail sent by Mike
Parker, Exxon Company, U.S.A., to Joseph Daly, U.S. EPA, August 7, 1998.
2. Candler, J.E., S. Hoskin, M. Churan, C.W. Lai and M. Freeman. "Sea-floor Monitoring
for Synthetic-Based Mud Discharged in the Western Gulf of Mexico," SPE 29694
Society of Petroleum Engineers Inc., March 1977.
3. Daan, R., K. Booij, M. Mulder, and E. Van Weerlee, "Environmental Effects of a
Discharge of Cuttings Contaminated with Ester-Based Drilling Muds in the North Sea,"
Environmental Toxicology and Chemistry, Vol. 15, No. 10, pp. 1709-1722, April 9, 1996.
4. Smith, J. and S.J. May, "Ula Wellsite 7/12-9 Environmental Survey 1991," a report to
SINTEF SI from the Field Studies Council Research Centre, November 1991.
5. The Pechan-Avanti Group, Worksheet regarding "Calculation of Model SBF Drilling
Fluid Formulation," October 26, 1998.
6. Baker-Hughes Inteq, Product information sheet featuring "Typical Formulation, 14.0
lb/gal / 70/30 SWR," 1995.
7. Friedheim, J. E., and H.L. Conn, "Second Generation Synthetic Fluids in the North Sea:
Are They Better?" IADC/SPE 35061, 1996.
8. Baker-Hughes Inteq, Product Bulletin for "ISO-TEQ," 1994.
9. Brandt/EPI, "The Handbook on Solids Control and Waste Management," 4th edition,
1996.
10. U.S. Environmental Protection Agency, Development Document for Effluent Limitations
Guidelines and New Source Performance Standards for the Offshore Subcategory of the
Oil and Gas Extraction Point Source Category, Final, EPA 821-R-93-003, January 1993.
11. The Pechan-Avanti Group, Worksheet regarding "Calculation of Organics in Waste
Cuttings Due to Crude Contamination," January 20, 1999.
12. SAIC, Worksheet regarding "Calculations for Average Density of Dry Solids in Cook
Inelt Drilling Mud," June 6, 1994.
13. Baker-Hughes Inteq, Material Safety Data Sheet for "MIL-BAR" (Barite), March
21,1994.
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14. Baker-Hughes Inteq, Case history information featuring synthetic-based drilling fluid
properties, 1995.
15. Daly, Joseph, U.S. EPA, Memorandum regarding "Contamination of Synthetic-Based
Drilling Fluid (SBF) with Crude Oil," January 14, 1999.
16. U.S. Environmental Protection Agency, Development Document for Final Effluent
Limitations Guidelines and Standards for the Coastal Subcategory of the Oil and Gas
Extraction Point Source Category, EPA 821-R-96-023, October 1996.
17. The Pechan-Avanti Group, "Demonstration of the 'Mud 10' Drilling Fluid Recovery
Device at the Amoco Marlin Deepwater Drill Site," August 7, 1998.
18. Annis, Max R., "Retention of Synthetic-Based Drilling Material on Cuttings Discharged
to the Gulf Of Mexico," prepared for the American Petroleum Institute (API) ad hoc
Retention on Cuttings Work Group under the API Production Effluent Guidelines Task
Force, August 29, 1997.
19. White, Charles E., and Henry D. Kahn, U.S. EPA, Statistics Analysis Section,
Memorandum to Joseph Daly, U.S. EPA, Energy Branch, regarding "Current
Performance, when using Synthetic-Based Drilling Fluids, for Primary Shakers,
Secondary Shakers, and Vibrating Centrifuge and Model Limits for Percent Retention of
Base Fluids on Cuttings for Secondary Shakers and Vibrating Centrifuge," January 29,
1999.
20. Mclntyre, Jamie, Avanti Corporation, Memorandum to Joseph Daly, U.S. EPA, regarding
"Summary of December 2 Meeting with David Wood of Mud Recovery Systems,"
December 18, 1997.
21. Annis, Max R., "Procedures for Sampling and Testing Cuttings Discharged While
Drilling with Synthetic-Based Muds," prepared for the American Petroleum Institute
(API) ad hoc Retention on Cuttings Work Group under the API Production Effluent
Guidelines Task Force, August 19, 1998.
22. Daly, Joseph, U.S. EPA, Memorandum regarding "Data Showing the Performance of the
Mud 10 with North Sea Oil Wells," January 14, 1999.
23. Munro, P.D., C.F Moffet and R.M. Stagg, "Biodegradation of Base Fluids Used in
Synthetic Drilling Muds in a Solid-Phase Test System," SPE 37861, 1997.
24. Daly, Joseph, U.S. EPA, Memorandum regarding "Cost of Synthetic-Based Drilling
Fluids (SBF)," January 15, 1999.
VII-45
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25. Still, I. and J. Candler, "Benthic Toxicity Testing of Oil-Based and Synthetic-Based
Drilling Fluids," Eighth International Symposium on Toxicity Assessment, Perth,
Western Australia, May 25-30, 1997.
26. U.S. EPA, "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, December 1992.
27. Daly, Joseph, U.S. EPA, Memorandum regarding "Meeting with Oil and Gas Industry
Representatives Regarding Synthetic Drilling Fluids," July 2, 1996, with two
attachments: 1) Information package entitled "Enhanced Mineral Oils (EMO) for
Drilling," presented by Exxon Co., U.S.A Marketing, Donald F. Jacques, Ph. D., June 25,
1996, and 2) Letter from Michael E. Parker, P.E., Exxon Company U.S.A., to M. B.
Rubin, U.S. EPA, September 17, 1996.
28. Hood, C.A., Baker-Hughes Inteq, Letter to Joseph Daly, U.S. EPA, with unpublished
sediment toxicity data from Baker-Hughes Inteq, July 9, 1997.
29. Candler, J., R. Herbert and A.J.J. Leuterman, "Effectiveness of a 10-day ASTM
Amphipod Sediment Test to Screen Drilling Mud Base Fluids for Benthic Toxicity," SPE
37890, Society of Petroleum Engineers Inc., March 1997.
30. American Petroleum Institute, Information package regarding "Data Tables for the
Conference Call for Review of 2nd Round of Range-Finders," API Drilling Mud Issue
Work Group ad hoc SBM Sediment Toxicity Protocol Development Work Group,
September 11, 1998.
31. American Petroleum Institute, Information package regarding "Conference Call for
Review of 3rd Round of Range-Finders," API Drilling Mud Issue Work Group ad hoc
SBM Sediment Toxicity Protocol Development Work Group, December 11, 1998.
32. Vik, E.A., S. Dempsey and B. Nesgard, "Evaluation of Available Test Results from
Environmental Studies of Synthetic Based Drilling Muds," OLF Project Acceptance
Criteria for Drilling Fluids, Aquateam Report No. 96-010, July 29, 1996.
33. Munro, P.D., C.F. Moffet, L. Couper, N.A. Brown, B. Croce, and R.M. Stagg,
"Degradation of Synthetic Mud Base Fluids in a Solid-Phase Test System," the Scottish
Office of Agriculture and Fisheries Department, Fisheries Research Services Report No.
1/97, January 1997.
34. U.S. EPA, 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, February 1999.
VII-46
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35. M-I Drilling Fluids, Bar graph entitled "M-I's Synthetics Marketplace," with notation it
was handed to J. Daly by J. Candler on January 30, 1997.
36. Mclntyre, Jamie, Avanti Corporation, Telephone Communication Report on conversation
with Peter Matthews, Newpark Drilling Fluids, regarding '"Centrifugal Dryer' for Drill
Cuttings," May 29, 1998.
37. Derrick Equipment Company, Product brochure entitled "Derrick HI-G Dryer with
Optional Hydrocyclone Packages," October 1997.
38. Mclntyre, J., Avanti Corporation, Telephone Communication Report on conversation
with Mike Montgomery, Brandt Company, regarding "Questions regarding Brandt solids
control equipment," with attached product bulletins, April 13, 1998.
39. Mclntyre, J., Avanti Corporation, Telephone Communication Report on conversation
with George Potts, Derrick Equipment Company, regarding "Questions regarding Derrick
solids control equipment," with attached price information, April 24, 1998.
40. Mclntyre, J., Avanti Corporation, Telephone Communication Report on conversations
with Paul Hanson (on April 20, 1998), and George Murphy (on April 24, 1998) of
SWACO, regarding "Questions regarding SWACO solids control equipment," with
attached product brochures.
41. Mclntyre, J., Avanti Corporation, Telephone Communication Report on conversation
with Bryan Murry, Broadbent, Inc., regarding "Questions regarding Broadbent solids
control equipment," with attached product brochure, April 15, 1998.
42. Mud Recovery Systems, Ltd., Product brochure entitled "M.U.D. 10 and M.U.D. 6 Mud
Recovery and Cuttings Cleaning System," undated.
43. Walters, Herb, "Dewatering of Drilling Fluids," in Petroleum Engineer International.
February 1991.
44. Veil, John A., Argonne National Laboratory, Washington, D.C., "Data Summary of
Offshore Drilling Waste Disposal Practices," prepared for the U.S. Environmental
Protection Agency, Engineering and Analysis Division, and the U.S. Department of
Energy, Office of Fossil Energy, November 1998.
45. Carriere, J. and E. Lee, Walk, Haydel and Associates, Inc., "Water-Based Drilling Fluids
and Cuttings Disposal Study Update," Offshore Effluent Guidelines Comments Research
Fund Administered by Liskow and Lewis, January 1989.
46. Kennedy, Kerri, The Pechan-Avanti Group, Telecommunications Report on conversation
with personnel at Frances Torque Service, regarding "Cuttings box rental costs (Gulf of
Mexico area)," June 4, 1998.
VII-47
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47. Kennedy, Kerri, The Pechan-Avanti Group, Telecommunications Report on conversation
with John Belsome, Seabulk Offshore Ltd., regarding "Offshore supply boat costs and
specifications," June 3, 1998.
48. Kennedy, Kerri, The Pechan-Avanti Group, Telecommunications Report on conversation
with George Bano, Sea Mar Management, regarding "Offshore supply boat costs and
specifications," June 3, 1998.
49. U.S. EPA, "Trip Report to Campbell Wells Land Treatment, Bourg, Louisiana, March 12,
1992," May 29, 1992.
50. Kennedy, Kerri, The Pechan-Avanti Group, Telecommunications Report on conversation
with Frank Lyon, Newpark Environmental, regarding "Drilling Waste Zero Discharge
Disposal Costs," May 19, 1998.
51. Mclntyre, Jamie, The Pechan-Avanti Group, Telecommunications Report on conversation
with Darron Stankey, McKittrick Solid Waste Disposal Facility, regarding "California
Prices for Land Disposal of Drilling Wastes," October 16,1998.
52. Mclntyre, Jamie, SAIC, Telecon on conversation with Josh Stenson, Carlisle Trucking,
regarding "Costs to Truck Wastes from Kenai, Alaska to Arlington, Oregon," May 23,
1995.
53. Montgomery, Richard, The Pechan-Avanti Group, Telecommunication Report on
conversation with Shane Morgan, Ecology Control Incorporated, regarding "costs
associated with land and water transport of drill cuttings and drilling fluids for offshore
oil platforms operating off the California coast," May 9, 1998.
54. Weideman, Allison, U.S. EPA, "Trip Report to Alaska Cook Inlet and North Slope Oil
and Gas Facilities, August 25-29, 1993," August 31, 1994.
55. Newpark Environmental Services, Facsimile of Price List, Effective May 1, 1998, from
Lisa L. Denman to Kerri Kennedy, May 26, 1998.
56. U.S. Liquids of Louisiana, Facsimile of Price List, from "Betty" to Jamie Mclntyre, May
26, 1998.
57. Mclntyre, Jamie, SAIC, Telecon on conversation with Alan Katel, Chemical Waste
Management of the Northeast, regarding "Cost of Disposing Drilling Wastes and Possible
Transportation Routes," May 9, 1995.
58. Kennedy, Kerri, The Pechan-Avanti Group, Telecommunications Report on conversation
with Todd Franklin, Apollo Services, regarding "Apollo Services drilling waste zero
discharge practices and cost," May 19, 1998.
VII-48
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59. Kennedy, Kerri, The Pechan-Avanti Group, Telecommunications Report on conversation
with Nubon Guidry, National Injection Services, regarding "Zero discharge practices for
OBM and SBM," April 29, 1998.
60. Kennedy, Kerri, The Pechan-Avanti Group, Telecommunications Report on conversation
with Gene Kraemer, National Injection Services, regarding "Zero discharge costs and
space requirements: Onsite injection," May 19, 1998.
61. Daly, Joseph, U.S. EPA, Memorandum regarding "October 13, 1998 Teleconference
Regarding SBF Use," October 20, 1998.
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CHAPTER VIII
COMPLIANCE COST AND POLLUTANT REDUCTION
DETERMINATION OF DRILLING FLUIDS AND DRILL CUTTINGS
1.0 INTRODUCTION
This chapter presents the incremental costs and pollutant reductions for the technology
based options considered for control of drill cuttings. Incremental compliance costs beyond
current industry practices and NPDES permit requirements were developed for the two control
options for the Gulf of Mexico, offshore California, and coastal Cook Inlet, Alaska. Compliance
costs were not developed for the other offshore regions where oil and gas activity exists or is
expected, because, as is discussed in earlier chapters of this document, discharges of drill cuttings
do not occur in these areas.
2.0 OPTIONS CONSIDERED AND SUMMARY COSTS
Two technology based options were considered for control and treatment of SBF drill
cuttings for this rule. These options are:
Discharge: Limitations on stock synthetic base fluid (PAH content,
biodegradation rate, sediment toxicity); limitations on discharged SBF cuttings
(no free oil, formation oil contamination, retention of SBF on cuttings);
limitations on Hg and Cd in stock barite; prohibition of diesel oil discharge.
Zero Discharge: Zero discharge for all areas.
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Table VIII-1 presents the annual incremental compliance costs and pollutant reductions
calculated for each option, for both existing and new sources. Both the costs and pollutant
reductions are based on current annual drilling activity in each of the three geographic regions, as
well as model well volumes and waste characteristics. The derivation of these costs and
pollutant reductions is described in detail in the remainder of this chapter.
3.0 COMPLIANCE COST METHODOLOGY
The costs considered as part of the compliance cost analysis are only those that EPA
believes will be affected by this rulemaking effort, including costs associated with the
technologies used to control and manage drill cuttings contaminated with SBF and OBF
(hereafter referred to as SBF-cuttings and OBF-cuttings) under the discharge and zero discharge
options, as well as savings incurred from the recovery of SBF.
The following sections describe first the general assumptions and input data on which the
cost analysis is based, followed by a detailed discussion of the methodology used to calculate the
annual incremental compliance costs for both BAT and NSPS levels of regulatory control.
3.1 DATA AND ESTIMATES USED TO GENERATE COSTS
3.1.1 Drilling Activity
Chapter IV of this document describes the accounting of wells drilled annually in each of
the three geographic areas, distinguishing between wells drilled using WBF, OBF, and SBF (see
section IV.3.1). For the purposes of calculating compliance costs, pollutant reductions, and non-
water quality environmental impacts, a population of wells considered to be affected by this rule
was derived from the total numbers of wells drilled annually that are listed in Table IV-2. The
affected well population, hereafter referred to as "in-scope wells," is a subset of the total annual
well counts. Wells currently drilled with SBF are included in the analysis, and also OBF wells
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TABLE VIII-1
ANNUAL INCREMENTAL COMPLIANCE COSTS AND
POLLUTANT REDUCTIONS FOR DRILL CUTTINGS BAT AND NSPS OPTIONS
Option
Incremenlal ( osi
(1997S/yr)
Incrcmcnlal Pollulani Reductions
(ll)s/\ 1')
BAT Options for Existing Sources
Discharge with 7% retention of
base drilling fluid on cuttings
($6,586,322)
Conventional
Priority Organics
Priority Metals
Non-Conventionals
Total
(16,334,088)
86
2,083
573,071
(15,758,848)
Zero Discharge
$6,963,896
Conventionals
Priority Organics
Priority Metals
Non-Conventionals
Total
157,248,923
267
6,690
1,847,872
159,103,752
NSPS Options for New Sources
Discharge with 7% retention of
base drilling fluid on cuttings
($619,475)a
Conventionals
Priority Organics
Priority Metals
Non-Conventionals
Total
1,519,236
16
337
90,805
1,610,394
Zero Discharge
$1,594,418
Conventionals
Priority Organics
Priority Metals
Non-Conventionals
Total
18,073,733
32
770
212,379
18,286,914
Total Costs and Pollutant Reductions (BAT + NSPS)
Discharge with 7% retention of
base drilling fluid on cuttings
($7,205,797)a
Conventionals
Priority Organics
Priority Metals
Non-Conventionals
Total
(14,814,852)
102
2,420
663,876
(14,148,454)
Zero Discharge
$8,558,314
Conventionals
Priority Organics
Priority Metals
Non-Conventionals
Total
175,322,656
299
7,460
2,060,251
177,390,666
'These numbers are slightly higher than the corresponding numbers ($569,600 and $7,155,921) in the Federal Register notice for this proposed
regulation because the results from the last revision were inadvertently excluded from the Federal Register notice.
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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 do not incur costs or realize 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 do not result in costs or savings in the analysis.
Referring to Table IV-2, the 113 SBF wells in the Gulf of Mexico are in scope. While the
rule applies to any wells discharging SBFs in areas where drilling wastes may be discharged, this
Development Document uses the phrase "in scope" to indicate facilities that incur costs or realize
savings under the rule. In addition, all OBF wells that are projected to convert to SBF are in
scope. This includes the 12 OBF wells in offshore California, one OBF well in Cook Inlet, and a
subset of the OBF wells in the Gulf of Mexico. Based on information provided by industry
sources, EPA estimated that 20% of the 112 Gulf of Mexico OBF wells accounted for in Table
IV-2, or 22.4 wells, would convert to SBF in the discharge option.1 To avoid calculations using
fractions of wells, this number was rounded to the next whole number, or 23 OBF wells. Thus,
the total number of in-scope wells in the discharge option is 149 wells per year (i.e.,
113+12+1+23). In offshore California and Cook Inlet, Alaska, EPA projected that all OBF
wells will convert to SBF because of the higher cost to drill, 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 Gulf of Mexico. For example, disposal of OBF-cuttings in Cook Inlet would
likely require the trucking or barging of the waste to the lower 48 states. Air quality in California
is a continuing concern, and there is pressure to keep air emissions from oil and gas drilling
activities in the neighboring offshore waters at a minimum. Also, this will be the first
opportunity for operators in California and Alaska to discharge SBF-cuttings, whereas in the Gulf
of Mexico, they already have the choice of using SBF and discharging the SBF-cuttings.
For comparison purposes, EPA varied the number of OBF wells in the Gulf of Mexico
that are assumed to convert from OBF to SBF in the discharge option. Compliance costs and
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pollutant reductions were calculated assuming zero%, 20%, and 100% of OBF wells in the Gulf
of Mexico would convert to SBF. The comparative results of these analyses are presented in
sections 3.2 and 4.2.2 of this chapter.
For the zero discharge option, only wells currently drilled using SBF are in-scope because
wells currently drilled with OBF are already at the zero-discharge level of compliance. Thus, the
total number of in-scope wells (those that would incur costs or realize savings) for the zero
discharge option is 113 SBF wells drilled per year in the Gulf of Mexico, including both existing
and new sources of drill cuttings.
3.1.2 Model Well Characteristics
Sections 3.0 and 4.0 of Chapter VII present the pollutant characteristics and drilling waste
volumes that EPA calculated on a per-well basis for the four model wells. Table VII-4 lists the
drilling fluid and drill cuttings waste volumes that are the basis for the compliance cost, pollutant
reduction, and non-water quality environmental impact analyses.
In addition to the per-well waste volumes, EPA estimated the number of days to drill each
model well, using the per-well retort data provided by API.2'3 These days represent the number
of days of active drilling using SBF, and do not represent the entire time that the drilling rig and
associated equipment are onsite. Active drilling days comprise approximately 40% of the time
the drilling equipment is onsite.4 These so-called active drilling days are used in equipment
rental cost estimates, and are the basis for estimating waste hauling requirements. The estimated
number of drilling days for the well sections drilled with SBF are as follows: 3.6 days for a
SWD, 7.5 for a SWE, 5.4 for a DWD, and 12.0 for a DWE. This range of drilling days was
confirmed by an industry source to be typical for drilling SBF intervals.4
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3.1.3 Onsite Solids Control Technology Costs
Costs associated with the onsite treatment of drill cuttings were estimated for both
baseline and BAT/NSPS compliance levels of control. The types of solids control equipment
currently used in the offshore oil and gas industry are described in detail in Chapter VII. The
following sections present the unit costs that comprise the line-items in the solids control
technology costs.
3.1.3.1 Baseline Solids Control Technology Costs
For the purpose of calculating incremental compliance costs, EPA identified a baseline
level of solids control consisting of a primary shale shaker (or multiple primary shakers aligned
in parallel), from which drill cuttings are either discharged without further treatment or collected
for transport to shore, followed by a secondary shale shaker that receives drilling fluid from the
primary shale shaker and discharges smaller drill solids than the primary shaker. The purpose of
the primary shaker is to receive the drilling fluid and drill cuttings that return from down hole,
and to make the first separation of cuttings from the drilling fluid. The purpose of the secondary
shaker is to remove the smaller solid particles that pass through the primary shaker, thereby
controlling the buildup of fine solids in the drilling fluid. In some cases, a centrifuge is used in
place of the secondary shale shaker, or as a tertiary treatment unit to return more SBF to the
active drilling system. Data supplied by API support the assumption that standard solids control
systems for wells drilled with SBF most often consist of primary and secondary shale shakers.3
As discussed in section VII.4.2.2, EPA estimated that the OBF- or SBF-cuttings discharged by a
standard solids control system have an average 11% retention of base fluid on a wet weight basis.
The line items in the baseline cost analysis for Gulf of Mexico wells that currently drill
with SBF consist of the cost of the currently-required SPP toxicity monitoring test and the cost of
SBF lost with the discharged cuttings. The SPP toxicity monitoring test was estimated to cost
$575 per test, at a frequency of once per well.5 The unit cost of SBF lost with discharged
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cuttings was estimated to be $200 per barrel (bbl) based on current prices for SBFs using internal
olefin as the base fluid.6'7 The volume of SBF adhering to the discharged cuttings, included in
Table VII-4 for each model well, is based on the weighted average 11% (wt.) retention value
calculated for the baseline solids control system, and varies with the model well size. No other
baseline costs (e.g., maintenance or labor costs) were attributed to the operation of solids control
equipment that EPA assumes to be standard in all drilling operations.
3.1.3.2 BAT/NSPS Compliance Solids Control Technology Costs
The BAT/NSPS compliance levels of control are based on a solids control technology
capable of reducing the retention of drilling fluid on cuttings consistently below that of standard
primary shale shakers. The technology is a vibrating centrifuge that receives drill cuttings from
the primary shale shaker and removes additional drilling fluid from the cuttings before they are
discharged.8 This unit is an add-on rather than a replacement technology. As discussed in
Chapter VII, compared to a primary shale shaker that produces cuttings with an estimated
average 10.6% (wt.) of base fluid (either synthetic or oil), the vibrating centrifuge reduces the
retention of base fluid to an estimated average 5.14% (wt.). When added to a baseline solids
control system, the vibrating centrifuge reduces the system-wide average retention of base fluid
on cuttings to 7% (wt.) (see section VII.4.2.2). Although the vibrating centrifuge is not currently
in wide-spread use in the U.S. offshore industry, it is a proven technology with widespread use in
the North Sea and demonstrated use in the Gulf of Mexico. Domestic interest in this equipment
was witnessed by EPA in a recent demonstration of this technology at an offshore drilling
operation in the Gulf of Mexico.7 EPA is also aware of recent efforts on the part of a solids
control company that serves the Gulf of Mexico region to develop and market a centrifuge device
capable of treating cuttings to low retention values, comparable to the one used in the North Sea.9
Line-item BAT/NSPS costs in the discharge option analysis consist of the following:
Costs associated with the use of an add-on solids control device: The cost of the add-on
technology is the daily rental cost for the vibrating centrifuge device, estimated to be
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$1,200 per day.7 The rental cost includes all equipment, labor and materials. The number
of rental days was calculated based on the assumption that active drilling days comprise
approximately 40% of the time the drilling equipment is onsite.4 The number of rental
days varies with the model well size, ranging from nine to 30 days.
Cost to retrofit platform space to accommodate the device: The unit retrofit cost was
derived from the Offshore Oil and Gas compliance cost analysis in which deck space was
estimated to be $250/ft2.10 This cost was adjusted to 1997 dollars using the Engineering
News Record's Construction Cost Index (ENR CCI) ratio of 1997$/1993$ (1.356),
resulting in an updated unit retrofit cost of $340/ft2.11 The amount of space required is the
sum of the footprints for the vibrating centrifuge (45.7 ft2), a drilling fluid holding tank
(20 ft2), plus a one-foot perimeter of free space around both footprints (8 ft2), for a total of
75 ft2 of retrofit space required.7'8 Retrofit costs were assigned to all existing sources but
not to new sources.
Value of the SBF discharged with the cuttings: The unit cost of SBF lost with
discharged cuttings varies between the geographic areas. In the Gulf of Mexico, the cost
is $200 per barrel (bbl).6'7 The unit cost in California was estimated to be $320/bbl,
calculated by multiplying the Gulf of Mexico unit cost by the geographic area cost
multiplier for California, 1.6.12 Geographic area cost multipliers, developed for the
Offshore Oil and Gas Rulemaking effort to estimate regional compliance costs, are the
ratio of equipment installation costs in a particular area compared to the costs for the
same equipment installation in the Gulf of Mexico, whose multiplier is l.12 The unit SBF
cost in Cook Inlet was estimated to be $400/bbl, based on a multiplier of 2. The
multipliers are used here to reflect shipping costs for materials manufactured in the Gulf
of Mexico area.
The volume of SBF adhering to the discharged cuttings, included in Table VII-4, is based
on the weighted average 7% (wt.) retention value calculated for the add-on solids control
system, and varies with the model well size.
Cost of performing the waste monitoring analyses: Analytical monitoring costs are
included for the proposed test for crude oil contamination of drill cuttings and retort
analysis for SBF retention on cuttings. The crude contamination test, estimated to cost
$50 per test13, would be administered once per well. The retort analysis for SBF
retention, estimated to cost $50 per test, would be required for each of the two streams of
discharged cuttings at a frequency of once per 500 feet of hole drilled.14 Therefore, the
per-well cost of retort monitoring tests varies with model well depth.
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3.1.4 Transportation and Onshore Disposal Costs
Costs associated with the transportation and land-based disposal of drill cuttings were
estimated for both baseline and BAT/NSPS compliance levels of control. Chapter VII describes
the modes of transportation and land disposal technologies currently used by the offshore oil and
gas industry. The following sections present the unit costs that comprise the line-items in the
transport and land disposal costs.
3.1.4.1 Baseline Transport and Disposal Costs
Wells currently drilled with OBF must either transport OBF-cuttings to shore for disposal
at land-based facilities or inject OBF-cuttings on site. As discussed in section VIII.3.1.1, EPA
estimated that 112 Gulf of Mexico wells, 12 offshore California wells, and one Cook Inlet well
are drilled annually using OBF. The line-item costs in the baseline transport and disposal
analysis include the following:
Supply Boat Costs: In all three geographic areas, drill cuttings are assumed to be
transported in supply boats for a day rate of $8,500 per day.15'16 The number of supply
boat days required to transport cuttings to shore was estimated using a methodology
developed in the Offshore Oil and Gas Rulemaking effort17, and varies with model well
size and geographic area. Appendix VIII-1 shows the calculation of supply boat transport
days for all three geographic areas.
Trucking Costs: Trucking costs are included as a separate line item for the offshore
California and coastal Cook Inlet baselines, while this cost is included as part of the
disposal facility cost in the Gulf of Mexico. The California trucking distance was
estimated as the distance between a port in the Oxnard/Ventura area and a disposal
facility in the vicinity of Bakersfield.17'18 The
trucking rate for California was calculated to be $354 per truckload, based on a 300 mile
round trip at 55 mph and $65 per hour.19 Each truck can carry two 25-bbl cuttings
boxes18, so for example, the number of truckloads required for a DWD model well is 29
(1,442 bbl/50 bbl per truckload). Appendix VIII-1 shows the calculation of truck trips for
all three geographic areas.
Due to the limited availability of land-based disposal facilities in the Cook Inlet area,
costs were developed for trucking the cuttings to a facility in Oregon. This approach to
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zero-discharge cost estimating for Cook Inlet was adopted from the Coastal Oil and Gas
Rulemaking effort.20 The trucking rate for Cook Inlet was calculated to be $1,917 per
truckload, updated from the 1995 cost of $1,800 per truckload used in the Coastal
guidelines effort20 using the ENR CCI ratio of 1997$/1995$ (1.065). The $1,800 per
truckload was based on a quote provided by a trucking company in Anchorage for hauling
wastes from the Kenai, Alaska area to a disposal facility in Arlington, Oregon.21 Each
truck has a capacity of 22 tons21 and can carry eight 8-bbl cuttings boxes, so that the
number of truckloads required for a SWD model well is 15.
Disposal and Handling Costs: In the Gulf of Mexico, an average unit disposal cost of
$10.13/bbl was calculated from current prices provided by two Gulf of Mexico area
companies for disposal of OBF cuttings (i.e., $9.50/bbl22 and 10.75/bbl23). This cost is
for activities at the disposal facility. An additional waste handling cost of $4.75/bbl was
included for dock usage, waste offloading with cranes, and transportation of the wastes
from the transfer station to the facility.22
The unit disposal cost for offshore California was calculated to be $12.32/bbl, based on a
unit cost of $35/ton18 and a density of 704 lbs/bbl cuttings (from the model well
characteristics presented in VII.4.2.3). Because this disposal cost is close to the per-
barrel disposal cost estimated for the Gulf of Mexico, a waste handling cost of $5.79/bbl
was added to the unit disposal cost of $12.32/bbl based on the ratio of handling to
disposal costs for the Gulf of Mexico (i.e., 0.47).
The unit disposal cost for drilling wastes generated in coastal Cook Inlet and transported
to Oregon was calculated to be $533 per 8-bbl box, updated from the 1995 cost of $500
per cuttings box used in the Coastal guidelines effort20 using the ENR CCI ratio of
1997$/1995$ (1.065). Because this cost translates to a higher per-barrel disposal cost
($66.63/bbl) than those quoted for facilities in the Gulf of Mexico and California areas, it
was assumed that the handling cost was included in the disposal cost and therefore was
not added as a separate cost.
Container Rental Costs: In both the Gulf of Mexico and offshore California, 25-bbl
reusable storage boxes are used to transport waste cuttings.15'17'24 In the Gulf of Mexico,
25-bbl cuttings boxes currently rent for an estimated $25/day.24'25 The rental rate in
California was estimated to be $40/day, calculated by multiplying the Gulf of Mexico
rental rate by the geographic area cost multiplier for California, 1.6.12
In coastal Cook Inlet, cuttings boxes hold eight barrels of waste cuttings, must be
purchased, and cannot be reused.20 The purchase price was estimated to be $133/box,
updated from the 1995 price of $125/box used in the Coastal guidelines effort20 using the
ENR CCI ratio of 1997$/1995$ (1.065).
For all three geographic areas, the number of cuttings boxes needed per well varies with
model well size. The number of cuttings box rental days was estimated to be equal to the
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supply boat transport days. Appendix VIII-1 shows the calculation of the supply boat
transport days for all three areas.
Value of the OBF disposed with the cuttings: In the baseline analysis, EPA assumed that
cuttings transported to shore for disposal would first be treated onsite by the baseline
solids control technology to an estimated 11% (wt.) retention of OBF on the disposed
cuttings. The unit cost of OBF was estimated to be $75/bbl for OBF wells in the Gulf of
Mexico6, adjusted to $120/bbl for offshore California and $150/bbl for coastal Cook Inlet
using their respective geographic area multipliers 1.6 and 2.0.12 The volume of OBF
adhering to the disposed cuttings, included in Table VII-4, varies with the model well
size.
3.1.4.2 BA T/NSPS Transport and Disposal Costs
Based on information provided by the industry, EPA assumed that all Gulf of Mexico
deep water wells would use SBF regardless of the level of regulatory control placed on the
discharged cuttings, due to the potential for riser disconnect and the spill of drilling fluid.26'27
Therefore, in the zero discharge option, EPA assumed that deep water wells would incur the cost
of lost SBF, rather than OBF, with the disposed cuttings. The unit cost of SBF lost with disposed
cuttings was estimated to be $200/bbl.6'7 Other than this line-item cost for deep water wells, zero
discharge option compliance costs are the same as the baseline zero discharge costs described
above in section Vin.3.1.4.1.
3.1.5 Onsite Grinding and Injection Costs
Costs associated with onsite grinding and injection of drill cuttings were estimated for
both baseline and BAT/NSPS compliance levels of control. As discussed in section VII.5.5,
only Gulf of Mexico operators currently employ onsite injection, although it has been tried
recently in both offshore California and coastal Cook Inlet.25 Based on information provided by
industry sources, EPA estimated that 20% of the wells that currently practice zero discharge in
the Gulf of Mexico do so by onsite injection.25 Preliminary information gathered regarding the
use of onsite injection in the Gulf of Mexico is inconsistent between sources, ranging from an
estimated 10% of zero discharge wells to as much as 67%.25 Additional information indicates
VIII-11
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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 onsite injection has increased throughout the industry since the time of the
Offshore Oil and Gas Rulemaking effort, and continues to grow.25,28 Chapter VII describes the
injection technology currently used by the offshore oil and gas industry.
The line-item and unit costs associated with onsite injection are identical for the baseline
and BAT/NSPS compliance cost analyses. Line-item costs include the day rate rental cost for a
turnkey injection system and the value of lost drilling fluid, all in the Gulf of Mexico geographic
area. The injection system cost of $4,280 per day includes all equipment, labor, and associated
services.29 The rental days for injection equipment were calculated by the same method used for
rental of the add-on vibrating centrifuge (see section Vin.3.1.3.2), based on the assumption that
active drilling days comprise approximately 40% of the time the drilling equipment is onsite.4
The number of rental days varies with the model well size, ranging from nine to 30 days. The
unit cost of drilling fluid injected with the cuttings was $75/bbl6 for the wells that EPA assumed
would convert to OBF under the zero discharge option, and $200/bbl for the wells that EPA
assumed would continue to use SBF under the zero discharge option.6'7
3.2 DETAILED ANALYSES OF COMPLIANCE COST OPTIONS
EPA first estimated baseline costs from current industry waste management practices, and
then estimated the cost to comply with each regulatory option. EPA then calculated the
incremental compliance costs, or the difference between baseline and compliance costs. Tables
Vin-2 and VIII-3 list, for existing and new sources respectively, the total annual baseline,
compliance, and incremental compliance costs calculated for each geographic area for both
regulatory options.
The compliance cost analysis was a step-wise process that began with the development of
a framework of "in-scope" wells that defined the well populations for each segment of the
VIII-12
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TABLE VIII-2
SUMMARY ANNUAL BASELINE, COMPLIANCE, AND
INCREMENTAL COMPLIANCE COSTS FOR
MANAGEMENT OF SBF-CUTTINGS FROM EXISTING SOURCES
(1997$/year)
Technology Basis
Guir oi*
Mexico
Offshore
California
Cook Inlel.
Alaska
Total
Baseline Costs
Discharge with 11% retention of
base fluid on cuttings
$19,113,650
NA
NA
$19,113,650
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
$15,590,550
$1,647,883
$115,467
$17,713,900
Zero Discharge via land disposal or
on-site injection
$26,077,546
$0
$0
$26,077,546
Incremental Compliance Costs (Savings)
Discharge Option Costs
($5,984,916)
($509,140)
($92,265)
($6,586,322)
Zero Discharge Option
$6,963,896
$0
$0
$6,963,896
analysis. As discussed in section VIII.3.1.1 above, the wells that incur costs or realize savings in
the compliance cost analysis are a subset of the total population of wells that EPA identified as
being drilled annually in the three geographic areas. Table VIII-4 shows the numbers of wells,
per model well, that EPA identified as in-scope for the cost analysis, shown separately for
existing and new sources.
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TABLE VIII-3
SUMMARY ANNUAL BASELINE, COMPLIANCE, AND
INCREMENTAL COMPLIANCE COSTS FOR
MANAGEMENT OF SBF-CUTTINGS FROM NEW SOURCES
(1997$/year)
Technology Basis
Costs
(Savings)
Baseline Costs
Discharge with 11% retention of base
fluid on cuttings
$2,201,725
NSPS Compliance Costs
Discharge with 7% retention of base
fluid on cuttings
$1,632,125
Zero Discharge via land disposal or on-
site injection
$3,796,143
Incremental NSPS Compliance
Costs
Discharge with 7% retention of base
fluid on cuttings
($619,475)a
Zero Discharge via land disposal or on-
site injection
$1,594,418
"This number is slightly higher than the corresponding number ($569,600) in the Federal Register notice for this proposed regulation
because the results from the last revision were inadvertently excluded from the Federal Register notice.
The next step of the analysis was the calculation of per-well costs developed from the
line-item costs detailed in section Vin.3.1 above. Referring to Table VIII-4, each box in the
table represents a set of wells for which a distinct per-well cost was calculated based on the line-
items appropriate to each set. The per-well costs were then multiplied by the number of wells in
each set, the results of which were then combined to calculate the industry-wide baseline,
compliance, and incremental compliance costs. Appendix VIII-2 consists of the detailed
worksheets that calculate the per-well costs, organized as follows:
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TABLE VIII-4
ESTIMATED NUMBER OF IN-SCOPE WELLS
DRILLED ANNUALLY3
Ciisl Aii;il\ sis l-'r;iiiK'\M>rk
Shallow Waler
<<1,000 I'D
Deep Waler
<> 1.000 ID
TOTAL
WILIS
Develop.
l'.\|)lnr.
l)e\elii|>.
r.\|)lnr.
Gulf of Mexico: Existing Sources
Baseline SBF Wells"
12
7
18
57
94
Baseline OBF Wells0
15
8
0
0
23
Discharge Option SBF Wellsd
27
15
18
57
117
Discharge Option OBF Wellsd
0
0
0
0
0
Zero Discharge Option SBF Wells6
0
0
18
57
75
Zero Discharge Option OBF Wells6
12
7
0
0
19
Gulf of Mexico: New Sources'
Baseline SBF Wellsb
1
0
18
0
19
Discharge Option SBF Wellsd
1
0
18
0
19
Zero Discharge Option SBF Wells6
1
0
18
0
19
Offshore California: Existing Sources8
Baseline OBF Wells6
1
0
11
0
12
Discharge Option SBF Wellsd
1
0
11
0
12
Coastal Cook Inlet: Existing Sources5
Baseline OBF Wells6
1
0
0
0
1
Discharge Option SBF Wellsd
1
0
0
0
1
a The numbers in this table are a subset of the estimated number of wells drilled annually, shown in Table IV-2.
b The sum of the existing and new source baseline SBF wells is 113, the number of wells EPA estimates is drilled annually
using SBF (see section IV.3.1).
c EPA estimates that 20% of the 112 wells currently drilled using OBF in the Gulf of Mexico and all OBF wells in offshore
California and coastal Cook Inlet will convert to SBF use under the discharge option (see section VIII. 3.1.1).
d All baseline wells are included in the discharge option.
e Only baseline SBF wells are included in the zero discharge option. EPA assumes that all baseline shallow-water SBF wells
will convert to OBF for economic reasons, and that all baseline deep-water wells will continue to use SBF for technical
reasons (see section VIII.3.2.2.1). No baseline OBF wells are included in the zero discharge option because current practice
for these wells is zero discharge.
f Of the 13 SWD wells drilled annually in the Gulf of Mexico, EPA estimates that 5% or 1 well is a "new source" well, and of
the 36 DWD wells drilled annually, 50% or 18 wells are "new source" wells (see section VIII.3.2.3).
g EPA estimates that no "new source" wells will be drilled in offshore California and coastal Cook Inlet (see section
VIII.3.2.3).
VIII-15
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Worksheets 1 through 3: Baseline costs for the Gulf of Mexico, offshore California, and
coastal Cook Inlet, respectively.
Worksheets 4 through 6: Discharge option costs for the three geographic areas (in the
same order as Worksheets 1-3).
Worksheets 7 through 9: Zero discharge option costs for transport and land-disposal,
onsite injection, and the weighted average costs, respectively.
The following sections describe the development of the per-well costs and the calculations used
for each regulatory option.
3.2.1 Discharge Option Compliance Costs
3.2.1.1 Baseline Discharge Option Costs
The baseline analysis for the discharge option consisted of all baseline wells listed in
Table VIII-4, including both SBF and OBF wells. Worksheets 1, 2, and 3 in Appendix VIII-2
show the detailed calculations of the per-well and area-wide baseline costs for the Gulf of
Mexico, offshore California, and coastal Cook Inlet, respectively. For baseline SBF wells in the
Gulf of Mexico, the line-item costs for discharge following solids control to an average 11%
(wt.) retention of synthetic base fluid (section VIII.3.1.3.1) were added to calculate the per-well
costs, which range from $78,175 for a SWD well to $261,575 for a DWE well. As in all other
per-well calculations, the per-well costs vary proportionately with the volume of waste generated
per model well. However, on a per-well basis, the baseline cost is the same for all model wells in
the Gulf of Mexico. The unit baseline cost for all wells that currently use SBF is $82 per barrel
of SBF-cuttings discharged.
Costs for baseline OBF wells in the Gulf of Mexico were calculated based on the
assumption that 80% of these wells transport cuttings to shore for disposal, and 20% inject
cuttings onsite.25 For each of the two baseline shallow-water OBF wells, per-well costs were
calculated for transport and disposal and for injection. Then for each model well, a weighted
VIII-16
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average per-well cost was calculated as follows:
Baseline GOM OBF Well Cost = (0.8 x Per-Well Transport & Disposal Cost) + (0.2 x Per-Well Injection Cost)
The per-well costs for baseline OBF wells in the Gulf of Mexico are $91,355 for a SWD well
and $181,437 for a SWE well. The unit baseline costs for these wells are $96 and $91 per barrel
of OBF-cuttings disposed, respectively. The total annual discharge option baseline cost for the
Gulf of Mexico is $22 MM (see Table VIII-2).
As stated in section Vin.3.1.4.1, the baseline costs for OBF wells in offshore California
and coastal Cook Inlet are for transport and disposal of OBF-cuttings. The per-well baseline
costs for offshore California are $184,725 for a DWD well and $125,046 for a SWD well. The
unit baseline costs for these wells are $128 and $131 per barrel of OBF-cuttings disposed,
respectively. The per-well baseline cost for coastal Cook Inlet is $207,733 for a SWD well, with
a corresponding unit cost of $218 per barrel of OBF-cuttings disposed. The per-well costs for
these areas differ from the Gulf of Mexico transport and disposal costs due to comparatively
higher costs of some line items in these areas (see section VIII.3.1.4.1). For example, the per-
well cost to transport and dispose cuttings from a SWD well in the Gulf of Mexico is $97,288,
while the per-well disposal cost for the same model well in offshore California is $125,046. The
total annual baseline costs for offshore California and Cook Inlet are $2.2 MM and $0.2 MM,
respectively, and the total industry-wide baseline cost is $24 MM (see Table VIII-2).
3.2.1.2 BAT 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% to 7% base fluid on
wet cuttings. Worksheets 4, 5, and 6 in Appendix VIII-2 present the detailed calculations of the
per-well and area-wide discharge option compliance costs for the Gulf of Mexico, offshore
VIII-17
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California, and coastal Cook Inlet, respectively.
In the Gulf of Mexico, the per-well discharge compliance costs for wells currently drilled
with SBF range from $60,673 to $191,073 across the four model wells. Worksheet 4 of
Appendix VIII-2 shows unit costs for the Gulf of Mexico wells ranging from $72 to $77 per
barrel of SBF-cuttings discharged. The total annual discharge compliance cost for Gulf of
Mexico wells is $16 MM (see Table VIII-2).
The line-item discharge compliance costs for offshore California and coastal Cook Inlet
are the same as those estimated for the Gulf of Mexico adjusted higher using geographic area
multipliers (see section Vin.3.1.3.2). The per-well discharge compliance costs for offshore
California wells are $141,067 for a DWD well and $96,147 for a SWD well, with corresponding
unit costs of $118 and $122 per barrel of SBF-cuttings discharged. The per-well discharge
compliance cost for coastal Cook Inlet is $115,467 for a SWD well, with a unit cost of $147 per
barrel of SBF-cuttings discharged. 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 VIII-2.
3.2.1.3 Incremental BAT Discharge Option Compliance Costs
The incremental cost is the difference between the baseline and the compliance cost, as
presented in Table VIII-2. The two components of the incremental costs are 1) the costs
associated with the compliance technology and 2) the value of the drilling fluid discharged with
the cuttings. Table VIII-5 shows the incremental compliance costs for the discharge option
separated into technology costs and drilling fluid costs. The overriding factor in the Gulf of
Mexico incremental discharge option cost is that, according to EPA analysis of baseline SBF
wells, the value of the recovered SBF, at $8.1 MM, is $5.0 MM greater than the $3.1 MM cost
of implementing the vibrating centrifuge model technology. Therefore, for baseline SBF wells in
the Gulf of Mexico, a net savings of $5.0 MM results from the discharge option. For baseline
VIII-18
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TABLE VIII-5
DETAILED INCREMENTAL BAT DISCHARGE OPTION COMPLIANCE COSTS
(1997$/year)
Wells l)\ Drilling l luitl
( osl hoiii
Cull of Mexico
OITshore
( alil'tii'iiia
( oaslal Conk
In lei
Baseline SBF Wells
Add-on Discharge Technology
$3,102,419
NA
NA
Drilling Fluid
($8,149,000)
NA
NA
Net Incremental Cost
($5,046,581)
NA
NA
Baseline OBF Wells
(assumed to convert to
SBF under the discharge
option)
Conversion from Zero
Discharge to Discharge
Technology
($1,425,635)
($941,500)
($122,865)
Drilling Fluid (conversion
from OBF to SBF)
$487,300
($432,360)
$30,600
Net Incremental Cost
($938,335)
($509,140)
($92,265)
All In-scope Discharge
Option Wells
TOTAL Incremental
Discharge Option Costs
($5,984,916)
($509,140)
($92,265)
OBF wells that EPA assumed would convert to SBF in the discharge option, the cost of losing
SBF with the discharged cuttings ($0.49 MM cost) is overshadowed by the savings realized as
these wells move from baseline zero discharge technology to the model discharge technology
($1.43 MM savings). The net savings for baseline OBF wells in the discharge option is $0.94
MM in the Gulf of Mexico. Combining these two savings gives a total savings (negative net
incremental discharge compliance cost) of $6.0 MM for Gulf of Mexico wells in the discharge
option.
Incremental discharge option costs for offshore California and coastal Cook Inlet 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 K for offshore California and $92 K for
VIII-19
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coastal Cook Inlet. Combining these savings with the $6.0 MM for Gulf of Mexico wells gives a
total annual incremental discharge option compliance cost savings of $6.6 MM.
For comparison purposes, two additional discharge option compliance cost analyses were
performed in which the fraction of current Gulf of Mexico shallow water OBF wells that are
assumed to convert to SBF was varied.30'31 In the analysis presented above, this fraction is 20%,
based on information provided by industry sources.1 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% or 100% of these wells would convert to SBF use. The
"zero% convert" analysis resulted in an annual incremental cost savings of $5.6 MM industry
wide, and the "100% convert" analysis resulted in an annual incremental savings of $10.2 MM.
The savings for the "20% convert" analysis falls between these values, at $6.6 MM. Thus,
regardless of the number of wells assumed to convert from OBF to SBF, the discharge option
results in industry-wide incremental cost savings.
3.2.2 Zero Discharge Option Compliance Costs
3.2.2.1 Baseline Zero Discharge Option Costs
The zero discharge option compliance cost analysis includes Gulf of Mexico wells
identified as currently being drilled with SBF. The wells included in the offshore California and
coastal Cook Inlet analyses, and the wells currently drilled with OBF in the Gulf of Mexico 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 technical concerns
(i.e., potential spills as a result of riser disconnect in the deep water), and those that would
convert to OBF under zero discharge requirements to use a less expensive drilling fluid. This
division is shown in Table VIII-4.
VIII-20
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The $19 MM baseline cost for the zero discharge option is the sum of the per-well
baseline costs for the four model wells that currently use SBF multiplied by the corresponding
number of in-scope wells from Table VIII-4. The per-well baseline costs for SBF wells are the
same as those described above in section VIII.3.2.1.1. The detailed calculation of these per-well
baseline costs is shown in Worksheet 1 of Appendix VIII-2.
3.2.2.2 BAT Zero Discharge Option Costs
Per-well zero discharge compliance costs incorporate the assumption that, of all zero
discharge cuttings generated in the Gulf of Mexico, 80% is hauled to shore for land-based
disposal and 20% is injected on-site (see also section VIII.3.1.5).25
Worksheets 7, 8, and 9 in Appendix VIII-2 present the calculation of per-well BAT zero
discharge costs. Worksheet 7 shows the per-well costs for transporting cuttings to land-based
disposal, Worksheet 8 shows injection costs, and Worksheet 9 calculates the weighted average
per-well costs using the equation presented in section VIII.3.2.1.1 above. The weighted average
per-well costs for zero discharge range from $91,355 for a SWD well to $350,990 for a DWE
well. The weighted average unit costs range from $91 per barrel of OBF-cuttings disposed for a
SWE well to $143 per barrel of SBF-cuttings disposed for a DWD well. The total annual zero
discharge compliance cost resulting from this analysis is $26 MM (see Table VIII-2).
3.2.2.3 Incremental Zero Discharge Option Costs
The positive incremental costs under the zero discharge option (total annual = $7.0 MM)
are the costs that Gulf of Mexico baseline SBF wells would incur moving from discharge to zero
discharge (see Table VIII-2).
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3.2.3 NSPS Compliance Cost Analysis
Table VIII-3 lists the summary results for the NSPS cost analysis. As shown in Table
VIH-4, EPA assumed 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 435.1 l(q), and exclude exploratory wells by
definition.12'20 EPA estimated that 50% of the DWD wells in the Gulf of Mexico would be new
sources because of the rapid expansion in the deep water areas. Because of the slower expansion
in Gulf of Mexico shallow water areas, EPA estimated that 5% of SWD wells would be new
sources.
The NSPS cost analysis consists of the same line-item costs as in the analysis for existing
sources, with the exception that retrofit (for the add-on discharge technology) 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. Appendix VIII-3 includes five worksheets that present the baseline costs
(Worksheet 1), the discharge option costs (Worksheet 2), and the zero discharge option costs
(Worksheets 3, 4, and 5) for new source wells. The per-well baseline costs for the NSPS wells
are $117,975 for a DWD well and $78,175 for a SWD well, with a unit cost of $82 per barrel of
SBF-cuttings discharged for both wells. The total NSPS baseline cost is $2.2 MM.
The discharge option per-well costs for NSPS wells are $84,750 for DWD wells and
$56,750 for SWD wells, with corresponding unit costs of $71 and $72 per barrel of SBF-cuttings
discharged. The total NSPS discharge option cost is $1.6 MM. The incremental NSPS
compliance cost for the discharge option ($1.6 MM minus $2.2 MM) is $-0.57 MM, or a savings
of $570,000.
The weighted average per-well costs for the zero discharge option, in which 80% of the
costs represent disposal via land disposal and 20% represent on-site injection, are $205,822 for
VIII-22
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DWD wells and $91,355 for SWD wells, with corresponding unit costs of $143 per barrel of
SBF-cuttings disposed and $96 per barrel of OBF-cuttings disposed. The total NSPS zero
discharge cost is $3.8 MM. The incremental NSPS cost for the zero discharge option ($3.8 MM
minus $2.2 MM) is $1.6 MM.
4.0 POLLUTANT REDUCTIONS
The methodology for estimating pollutant loadings and incremental pollutant reductions
effectively parallels that of the compliance cost analysis. The pollutant reduction analysis is
based on the size and number of the four model wells identified in Table VIII-4, as well as
pollutant characteristics of the cuttings wastestream compiled from previous rulemaking efforts
and from industry sources. The following sections describe first the estimates and input data on
which the pollutant reductions analysis is based, followed by a detailed discussion of the
methodology used to calculate the annual incremental reductions for both BAT and NSPS levels
of regulatory control.
4.1 DATA AND ESTIMATES USED TO GENERATE POLLUTANT REDUCTIONS
To calculate per-well pollutant loadings and incremental pollutant reductions, EPA
characterized the cuttings wastestream in terms of pollutant concentrations. The pollutant
concentrations derive from three sources: mineral oil-based drilling fluid or internal olefin
synthetic-based drilling fluid, drill cuttings, and formation oil. Sections VII.3.1, VII.3.2 and
VII.3.3 of this document present detailed discussions of the characteristics of these sources that
EPA considered in its analysis of pollutant loadings and reductions. Table VII-1 lists the
pollutant concentrations that EPA used to calculate pollutant loadings.
In addition to pollutant concentrations, EPA estimated per-well waste volumes, as
presented in section VII.4.2.3. For each model well, two sets of calculations were developed, at
11% and 7% retentions, to determine the per-well volumes of mineral oil or synthetic base fluid,
VIII-23
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water, barite, dry cuttings and formation oil in the wastestream. Table VII-4 lists the specific
waste volumes EPA calculated for the four model wells.
The general assumptions EPA used to develop model waste volumes and pollutant
concentrations are summarized as follows:
Model drilling waste volumes are based on four model wells, as shown in Table
VII-4.
Total hole volume equals gage hole plus 7.5% additional volume due to washout
(see section VII.4.2.1).
There is no difference in the performance of OBF and SBF with regard to solids
separation processes (see section VII.5.2).
Model formulation for SBFs and OBFs is 47% (wt.) base fluid, 33% (wt.) solids,
20% (wt.) water, and this formulation remains constant throughout the solids
control system (see section VII.3.1).
All solids in a model drilling fluid are barite (see section VII.3.1).
Model drilling waste components are drilling fluid (SBF or OBF), dry cuttings,
and 0.2% (vol.) formation oil (see section VII.3.3).
Model retention values for drilling fluid on cuttings is 11% for baseline wells and
7% for discharge option wells (see section VIII.4.2.2).
4.2 INCREMENTAL POLLUTANT REDUCTIONS METHODOLOGY
The waste volume estimates listed in Table VII-4 were multiplied by the pollutant
concentrations in Table VII-1 to determine the per-well pollutant loadings. 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, as listed in Table VIII-4, to determine the total industry-wide pollutant
loadings. Incremental pollutant reductions were then calculated as the difference between
baseline loadings and compliance loadings. Appendix VIII-4 consists of the detailed worksheets
that calculate the per-well loadings and reductions, organized as follows:
VIII-24
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Worksheets 1 through 4: Baseline loadings for DWD, DWE, SWD, and SWE wells,
respectively.
Worksheets 5 through 8: Discharge option loadings and incremental reductions for the
four model wells (in the same order as Worksheets 1-4).
Worksheets 9 through 12: Zero discharge option loadings and incremental reductions for
the four model wells (in the same order as Worksheets 1-4).
All worksheets mentioned in the following text are from Appendix VIII-4.
The per-well loadings and reductions in Appendix VIII-4 were then multiplied by the
corresponding numbers of in-scope wells from Table VIII-4. Table VIII-6 presents the industry-
wide results in terms of baseline loadings, compliance loadings, and incremental reductions, for
both the discharge and zero discharge options, discussed below.
4.2.1 BAT Baseline Pollutant Loadings
As in the compliance cost analysis, EPA established a BAT baseline by calculating
pollutant loadings for the baseline wells identified as in-scope in Table VIII-4. For wells that
currently discharge (baseline SBF wells), baseline pollutant loadings were calculated assuming
the current practice of treating cuttings to 11% retention (see section VIII.3.1.3.1). The total
baseline loading for SBF wells is 159 MM lbs (see Table VIII-6). Baseline OBF wells in
offshore California, coastal Cook Inlet, and the Gulf of Mexico all have baseline loadings of zero
because OBF wells meet zero discharge requirements.
4.2.2 BAT Discharge Option Pollutant Reductions
In addition to baseline loadings, EPA calculated pollutant loadings resulting from
compliance with the discharge option add-on technology (see section VIII.3.1.3.2). In the Gulf
of Mexico, discharge option loadings are measured from two baselines: 1) SBF wells that move
VIII-25
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TABLE VIII-6
SUMMARY ANNUAL POLLUTANT LOADINGS AND
INCREMENTAL REDUCTIONS FOR MANAGEMENT OF SBF CUTTINGS FROM
EXISTING SOURCES
(lbs/year)
Guir oi*
Mexico
OH'shore
California
Cook Inlel.
Alaska
Total
Baseline Technology Loadings
Discharge with 11% retention of
base fluid on cuttings
159,103,752
NA
NA
159,103,752
Zero Discharge via land disposal
or on-site injection
0
0
0
0
Compliance Option Loadings
Discharge with 7% retention of
base fluid on cuttings
163,851,174
10,420,876
590,550
174,862,600
Zero Discharge via land disposal
or on-site injection
0
0
0
0
Incremental Pollutant Reductions (Loadings)
Discharge with 7% retention of
base fluid on cuttings
(4,747,422)
(10,420,876)
(590,550)
(15,758,848)
Zero Discharge via land disposal
or on-site injection
159,103,752
0
0
159,103,752
from 11% to 7% retention and 2) OBF wells that move from zero discharge to discharge at 7%
retention. The total annual discharge option loading for the Gulf of Mexico, shown in Table
VIII-6 as 164 MM lbs, resulted from the per-well loadings in Worksheets 5 through 8 multiplied
by the numbers of corresponding "discharge option SBF wells" listed in Table VIII-4. Likewise,
the per-well loadings in Worksheets 5 through 8 were multiplied by the numbers of "discharge
option SBF wells" in offshore California and coastal Cook Inlet for the respective total annual
VIII-26
-------
loadings of 10.4 MM lbs and 0.6 MM lbs (see Table VIII-6).
The incremental pollutant reductions were calculated by subtracting the compliance
loadings from the baseline loadings. For all three geographic areas, the discharge option
compliance loadings are greater than the baseline loadings, resulting in incremental increases.
These increases are indicated in Table VIII-6 as negative pollutant reductions. However, EPA
projects that only the discharge of dry cuttings will increase, while the amounts of discharged
synthetic drilling fluid and formation oil will decrease. The results of the incremental analysis
broken out by pollutant source are as follows:
SBF base fluid and barite: Discharges decreased by 10,142,406 lbs
Formation oil: Discharges decreased by 17,366 lbs
Dry cuttings: Discharges increased by 25,918,620 lbs.
This yields a net increase of 15.8 MM lbs discharged annually, due to the increased amount of
drill cuttings discharged from OBF wells that convert to SBF wells (see Table VIII-6).
As stated in section VIII.3.2.1.3, EPA investigated the range of incremental compliance
costs and pollutant reductions that result assuming that, in the discharge option, either zero% or
100% of current OBF wells convert to SBF. The analysis above is based on 20% of the OBF
wells converting to SBF. The "zero% convert" analysis resulted in an annual incremental
pollutant reduction of 3 MM lbs industry wide, and the "100% convert" analysis resulted in an
incremental increase of 89 MM lbs per year.3233 The increased discharges for the "20% convert"
analysis fall between these values, at 15.8 MM lbs (see Table VIII-6). In the 100% convert
scenario, the 89 MM lbs consists of 76 MM lbs of dry cuttings and 13 MM lbs of associated
SBFs.
VIII-27
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4.2.3 BAT Zero Discharge Option Pollutant Reductions
As shown in Table VIII-6, the pollutant loadings for compliance with the zero discharge
option are zero. The incremental pollutant reduction is the difference between the baseline
loading of currently discharging SBF wells at 11% retention and the loading of zero at zero
discharge. Table VIII-6 shows the annual incremental pollutant reduction for the zero discharge
option is 159 MM lbs.
4.2.4 NSPS Pollutant Reductions Analysis
The method of estimating pollutant loadings and reductions for new sources is the same
as described above for existing sources. As shown in Table VIII-4, EPA estimated that 19 new
sources wells are drilled in the Gulf of Mexico annually. Table VIII-7 shows the baseline
loadings, compliance loadings, and incremental compliance pollutant reductions for new source
wells. In this analysis, there are incremental pollutant 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% retention of synthetic base fluid on cuttings to discharge at 7% retention under
the discharge option or to zero discharge under the zero discharge option. No OBF wells are in
the NSPS baseline, so no wells incur pollutant discharge increases. The total annual NSPS
incremental pollutant reduction for the discharge option is 1.6 MM lbs, consisting of
approximately 1.6 MM lbs of SBF and a small amount (2,800 lbs) of formation oil. The annual
NSPS incremental reduction for the zero discharge option is 18.3 MM lbs.
5.0 BCT COMPLIANCE COSTS AND POLLUTANT REDUCTIONS
The BCT cost test evaluates the reasonableness of BCT candidate technologies as
measured from BPT level compliance costs and pollutant reductions. The proposed BCT level of
regulatory control is equivalent to the BPT level of control for both the 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.
VIII-28
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TABLE VIII-7
SUMMARY ANNUAL POLLUTANT LOADINGS AND
INCREMENTAL REDUCTIONS FOR MANAGEMENT OF SBF CUTTINGS FROM
NEW SOURCES
(lbs/year)
Technology lisisis
l.oiHlings/Ucriiiclion
s
Baseline Loadings
Discharge with 11% retention of base
fluid on cuttings
18,286,914
NSPS Pollutant Loadings
Discharge with 7% retention of base
fluid on cuttings
16,676,538
Zero Discharge via land disposal or
on-site injection
0
Incremental NSPS Pollutant
Reductions
Discharge with 7% retention of base
fluid on cuttings
1,610,394
Zero Discharge via land disposal or
on-site injection
18,286,914
VIII-29
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6
1
2
3
4
5
6
7
8
9
1'
1
REFERENCES
Daly, Joseph, U.S. EPA, Memorandum regarding "Phone Conversations Regarding
Number of Wells Likely to Switch from Using OBF to SBF Post SBF Effluent
Guidelines," October 28, 1998.
The Pechan-Avanti Group, Worksheet regarding "Number of Days to Drill Model SBF
Wells," October 27, 1998.
Annis, Max R., "Retention of Synthetic-Based Drilling Material on Cuttings Discharged
to the Gulf Of Mexico," prepared for the American Petroleum Institute (API) ad hoc
Retention on Cuttings Work Group under the API Production Effluent Guidelines Task
Force, August 29, 1997.
Daly, Joseph, U.S. EPA, Memorandum regarding "October 13, 1998 Teleconference
Regarding SBF Use," October 20, 1998.
Montgomery, Richard, The Pechan-Avanti Group, Telecommunication report on
conversation with David Daniel, Environmental Enterprises, regarding "Cost Associated
with Drilling Fluid Regulatory Options," October 15, 1998.
Daly, Joseph, U.S. EPA, Memorandum regarding "Cost of Synthetic-Based Drilling
Fluids (SBF)," January 15, 1999.
The Pechan-Avanti Group, "Demonstration of the 'Mud 10' Drilling Fluid Recovery
Device at the Amoco Marlin Deepwater Drill Site," August 7, 1998.
Mud Recovery Systems, Ltd., Product brochure entitled "M.U.D. 10 and M.U.D. 6 Mud
Recovery and Cuttings Cleaning System," undated.
Mclntyre, Jamie, Avanti Corporation, Telephone Communication Report on conversation
with Peter Matthews, Newpark Drilling Fluids, regarding "'Centrifugal Dryer' for Drill
Cuttings," May 29, 1998.
Science Applications International Corporation, "Final: Offshore Oil and Gas Industry:
Analysis of the Cost and Pollutant Removal Estimates for the BCT, BAT, and NSPS
Options for the Drill Cuttings and Drilling Fluid Streams," submitted to the U.S.
Environmental Protection Agency, Engineering and Analysis Division, January 13, 1993.
Engineering News Record, "Construction Cost Index History (1908-1997)," website
address http://www.enr.com/cost/costcci.htm, June 8, 1998.
VIII-30
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12. U.S. Environmental Protection Agency, Development Document for Effluent Limitations
Guidelines and New Source Performance Standards for the Offshore Subcategory of the
Oil and Gas Extraction Point Source Category, Final, EPA 821-R-93-003, January 1993.
13. Mclntyre, Jamie, The Pechan-Avanti Group, Telecommunication Report on conversation
with John Candler, M-I Drilling Fluids, regarding "Cost Estimates for Proposed RPE
Method," October 16, 1998.
14. Annis, Max R., "Procedures for Sampling and Testing Cuttings Discharged While
Drilling with Synthetic-Based Muds," prepared for the American Petroleum Institute
(API) ad hoc Retention on Cuttings Work Group under the API Production Effluent
Guidelines Task Force, August 19, 1998.
15. Kennedy, Kerri, The Pechan-Avanti Group, Telecommunications Report on conversation
with John Belsome, Seabulk Offshore Ltd., regarding "Offshore supply boat costs and
specifications," June 3, 1998.
16. Kennedy, Kerri, The Pechan-Avanti Group, Telecommunications Report on conversation
with George Bano, Sea Mar Management, regarding "Offshore supply boat costs and
specifications," June 3, 1998.
17. Carriere, J. and E. Lee, Walk, Haydel and Associates, Inc., "Water-Based Drilling Fluids
and Cuttings Disposal Study Update," Offshore Effluent Guidelines Comments Research
Fund Administered by Liskow and Lewis, January 1989.
18. Mclntyre, Jamie, The Pechan-Avanti Group, Telecommunications Report on conversation
with Darron Stankey, McKittrick Solid Waste Disposal Facility, regarding "California
Prices for Land Disposal of Drilling Wastes," October 16,1998.
19. Montgomery, Richard, The Pechan-Avanti Group, Telecommunication Report on
conversation with Shane Morgan, Ecology Control Incorporated, regarding "costs
associated with land and water transport of drill cuttings and drilling fluids for offshore
oil platforms operating off the California coast," May 9, 1998.
20. U.S. Environmental Protection Agency, Development Document for Final Effluent
Limitations Guidelines and Standards for the Coastal Subcategory of the Oil and Gas
Extraction Point Source Category, EPA 821-R-96-023, October 1996.
21. Mclntyre, Jamie, SAIC, Telecon on conversation with Josh Stenson, Carlisle Trucking,
regarding "Costs to Truck Wastes from Kenai, Alaska to Arlington, Oregon," May 23,
1995.
22. Newpark Environmental Services, Facsimile of Price List, Effective May 1, 1998, from
Lisa L. Denman to Kerri Kennedy, May 26, 1998.
VIII-31
-------
23. U.S. Liquids of Louisiana, Facsimile of Price List, from "Betty" to Jamie Mclntyre, May
26, 1998.
24. Kennedy, Kerri, The Pechan-Avanti Group, Telecommunications Report on conversation
with personnel at Frances Torque Service, regarding "Cuttings box rental costs (Gulf of
Mexico area)," June 4, 1998.
25. Veil, John A., Argonne National Laboratory, Washington, D.C., "Data Summary of
Offshore Drilling Waste Disposal Practices," prepared for the U.S. Environmental
Protection Agency, Engineering and Analysis Division, and the U.S. Department of
Energy, Office of Fossil Energy, November 1998.
26. American Petroleum Institute, responses to EPA's "Technical Questions for Oil and Gas
Exploration and Production Industry Representatives," attached to e-mail sent by Mike
Parker, Exxon Company, U.S.A., to Joseph Daly, U.S. EPA, August 7, 1998.
27. Daly, Joseph, U.S. EPA, Memorandum regarding "May 8-9, 1997, Meeting in Houston,
Texas-Inception of Industry/Stakeholder Work Groups to Address Issues of Discharges
Associated with Synthetic-Based Drilling Fluids (SBF)," January 14, 1999.
28. Kennedy, Kerri, The Pechan-Avanti Group, Telecommunications Report on conversation
with Mike Singler, National Injection Services, regarding "NIS Drilling Waste Zero
Discharge Technology and Costs," May 11, 1998.
29. The Pechan-Avanti Group, Worksheet regarding "Calculation of Daily Onsite Injection
Cost, October 30, 1998.
30. The Pechan-Avanti Group, "BAT Compliance Cost Analysis: '0% OBF Wells Convert'
Scenario," prepared for Joseph Daly, U.S. EPA, Office of Water, Engineering and
Analysis Division, January 21, 1999.
31. The Pechan-Avanti Group, "BAT Compliance Cost Analysis: '100% OBF Wells
Convert' Scenario," prepared for Joseph Daly, U.S. EPA, Office of Water, Engineering
and Analysis Division, January 21, 1999.
32. The Pechan-Avanti Group, "BAT Pollutant Reductions Analysis: '0% OBF Wells
Convert' Scenario," prepared for Joseph Daly, U.S. EPA, Office of Water, Engineering
and Analysis Division, January 20, 1999.
33. The Pechan-Avanti Group, "BAT Compliance Cost Analysis: '100% OBF Wells
Convert' Scenario," prepared for Joseph Daly, U.S. EPA, Office of Water, Engineering
and Analysis Division, January 20, 1999.
VIII-32
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CHAPTER IX
NON-WATER QUALITY ENVIRONMENTAL IMPACTS AND
OTHER FACTORS
1.0 INTRODUCTION
The elimination or reduction of one form of pollution has the potential to aggravate other
environmental problems, an effect frequently referred to as cross-media impacts. Under sections
304(b) and 306 of the Clean Water Act, EPA is required to consider non-water quality
environmental impacts in developing effluent limitations guidelines and new source performance
standards. Accordingly, EPA has evaluated the effect of these regulations on air pollution,
energy consumption, solid waste generation and management, and consumptive water use.
Safety, impacts of marine traffic, and other factors related to implementation were also
considered. EPA evaluated the non-water quality environmental impacts on a geographic as well
as an industry-wide basis.
2.0 SUMMARY OF NON-WATER QUALITY ENVIRONMENTAL IMPACTS
Regulatory options were developed to analyze the costs and pollutant loadings/reductions
for drill cuttings in each of the three geographic areas: Gulf of Mexico, offshore California, and
coastal Cook Inlet, Alaska (see Chapter VIII). Non-water quality environmental impacts
(NWQEI) were estimated for the technologies considered to be the bases for each of the selected
regulatory options and areas. The control technology bases for compliance with the options
considered for drill cuttings are 1) an add-on solids control device to reduce the amount of
IX-1
-------
adhering SBF in the cuttings wastestream for the discharge option, and 2) a combination of
transportation of drill cuttings to shore for disposal and onsite grinding followed by subsurface
injection for the zero discharge option. In order to assess the incremental impact of each of the
options, baseline impacts of current solids control practices were also determined. The
incremental reductions of NWQEI associated with the treatment and control of these wastes from
existing and new sources are summarized in Table IX-1.
For existing and new sources under the discharge option, EPA estimates that air
emissions would be reduced by a total of 72 tons per year, whereas if the zero discharge option
were selected, air emissions would increase by 380 tons per year. Therefore, in moving from the
zero discharge option to the discharge option, NWQEI in terms of air emissions would be
reduced by 452 tons per year. In addition, EPA estimates that 29,359 BOE less fuel would be
used (see Table IX-1).
Other favorable NWQEI occur with the elimination of the long-term disposal of OBF-
cuttings onshore, because such disposal can adversely 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 86,000 tons per
year, and the amount injected by 20,000 tons per year. The methodology used to arrive at these
results is described in the sections that follow.
3.0 ENERGY REQUIREMENTS AND AIR EMISSIONS
EPA calculated energy requirements and air emissions for both BAT and NSPS
regulatory levels of control. The assumptions and analyses presented in this section follow
directly from the assumptions and data used in the compliance cost and pollutant reductions
analyses presented in Chapter VIII.
IX-2
-------
TABLE IX-1
SUMMARY ANNUAL NWQEI
FOR DRILL CUTTINGS3
Option
Reduction
in Air
Emissions
(tons/yr)
Reduction in
1 uel
Usage
(BOE/yr)"
Reduction in Solid Waste
Disposed hv Zero
Discharge Technologies
(tons/vr)'
BAT Options for Existing Sources
Discharge with 7% retention of
base drilling fluid on cuttings
73.31
2,613
16,918
Zero Discharge
(338.55)
(24,125)
(82,455)
NSPS Options for New Sources
Discharge with 7% retention of
base drilling fluid on cuttings
(1.28)
(311)
0
Zero Discharge
(41)
(2,932)
(6,549)
Total BAT and NSPS Option NWQEI
Discharge with 7% retention of
base drilling fluid on cuttings
72.03
2,302
16,918
Zero Discharge
(379.55)
(27,057)
(89,004)
3 The positive numbers in this table represent reduced impacts as measured from the baseline, and the numbers in
parentheses represent increased impacts as measured from the baseline.
BOE (barrels of oil equivalent) is the sum of the diesel (42 gal diesel = 1 BOE) and natural gas (1,000 scf=
0.178 BOE) estimated for each compliance option.
c Landfill and subsurface injection.
In general, EPA estimated energy requirements by calculating the fuel consumption (in
terms of the fuel usage rate) of the equipment and activities associated with each of the
regulatory options. The fuel usage rate is expressed as barrels of oil equivalents (BOE) because
the fuel source for cuttings management can be either diesel oil or natural gas. BOE equates
natural gas fuel usage with that of diesel by expressing both fuel types in terms of barrels of oil.
EPA calculated diesel fuel usage by multiplying the time of equipment operation by the fuel
IX-3
-------
consumption rate specific to the activity or equipment. For diesel, the conversion factor to BOE
is 42 gallons = 1 BOE. The natural gas fuel usage was calculated by first determining the power
requirements of the equipment (expressed in horsepower) and multiplying it by the natural gas
usage rate. For natural gas, the conversion factor to BOE is 1,000 standard cubic feet (scf) =
0.178 BOE.1
EPA estimated air emissions of operations associated with each of the regulatory options
by using emission factors relating the production of air pollutants to period of time that the
equipment is operated and the amount of fuel consumed.
As in the cost analysis, energy requirements and air emissions were estimated using a
step-wise methodology. First, impacts were determined for current baseline activities (see
sections VIII.3.1.1 and VIII.3.2 for full discussions of baseline activities). Then compliance
impacts were estimated from the activities associated with each of the regulatory options
(discharge and zero discharge). Finally, the incremental impacts for each of the options were
calculated by subtracting the compliance impacts from the baseline impacts. Table IX-2 presents
the results of each of these steps for both air emissions and fuel usage.
Appendix IX-1 consists of the detailed worksheets that calculate the per-well energy
requirements and air emissions, organized as follows:
Worksheets 1 through 3: Baseline energy requirements and air emissions for wells in the
Gulf of Mexico, offshore California, and coastal Cook Inlet, respectively.
Worksheets 4 through 6: BAT discharge option energy requirements and air emissions
for the three geographic areas (in the same order as in Worksheets 1-3).
Worksheets 7 through 9: BAT zero discharge option energy requirements and air
emissions for transport and land-disposal, onsite injection, and the weighted average
impacts, respectively.
These worksheets are referred to throughout the following sections.
IX-4
-------
TABLE IX-2
SUMMARY BAT AIR EMISSIONS
AND FUEL USAGE
Compliance Tcchnoloiiv
Aii* I'lmissioiis ((oiin/\ n
l iicl I sage (U()r./J n
c.uii or
Mexico
OITshorc
CA
CI,
Alaska
Tolal
(.uiror
Mexico
OITshorc
CA
CI,
Alaska
Tolal
Baseline Emissions & Fuel Usage
Discharge at 11% retention
(SBF users only)
0
NA
NA
0
0
NA
NA
0
Zero Discharge
(OBF users only)
47.92
36.61
2.08
86.61
3,433
2,121
285
5,839
Total Compliance Emissions & Fuel Usage
Discharge at 7% Option
12.54
0.76
0.01
13.30
3,035
187
4
3,226
Zero Discharge Option
338.55
NA
NA
338.55
24,125
NA
NA
24,125
Incremental Compliance Emissions & Fuel Usage Reductions (Increases)
Discharge at 7% Option
35.38
35.86
2.07
73.31
398
1,934
281
2,613
Zero Discharge Option
(338.55)
0
0
(338.55)
(24,125)
0
0
(24,125)
3.1 ENERGY REQUIREMENTS
The following sections present the detailed assumptions, per-well data, and methodology
used to calculate incremental energy requirements and fuel usage resulting from each regulatory
option.
IX-5
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3.1.1 Baseline Energy Requirements
In developing baseline energy requirements, EPA assumed that the 94 wells drilled
annually in the Gulf of Mexico with SBF discharge SBF-cuttings with an average 11% base
fluid. Also, wells currently drilled with OBF that convert to SBF are included in the baseline,
with the assumption that they currently practice zero discharge by either hauling waste OBF-
cuttings to shore for land-based disposal or by onsite injection. This includes 20%, or 23 wells,
of the 112 OBF wells drilled annually in the GOM, all 12 OBF wells drilled annually in offshore
California, and one OBF well drilled annually in Cook Inlet, Alaska. Table VIII-4 presents the
framework of "in-scope" wells (wells that would incur costs or realize savings as a result of this
rule) that EPA estimates would be affected by the proposed regulation, distinguished by the type
of drilling fluid used at baseline and compliance levels. In the context of the NWQEI analysis,
SBF wells using standard solids control equipment and discharging SBF-cuttings at 11%
retention are defined as the baseline. Increases or decreases in NWQEIs 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.
The total baseline energy requirements were determined by summing the individual
energy consuming activities currently performed on a per-well basis and multiplying by the
number of in-scope wells per geographic area. A summary of the baseline energy requirements is
presented in Table IX-2 by geographic area.
The assumptions, data, and methods used to develop the per-well baseline zero discharge
fuel usage rates are identical to those used in the zero discharge option compliance analysis.
Therefore, this section presents an overview of the methodology in terms of the baseline analysis,
and section IX.3.1.3, "Zero Discharge Option Energy Requirements," presents the detailed line-
IX-6
-------
item assumptions and data applicable to both the baseline and compliance zero discharge
analyses.
Per-well baseline fuel usage rates for OBF wells in offshore California and coastal Cook
Inlet derive from activities associated with transporting waste drill cuttings to shore and land-
disposing the cuttings. For this analysis, EPA applied the methods developed to estimate zero
discharge impacts under the Offshore Rulemaking for offshore California wells2 and under the
Coastal Rulemaking for coastal Cook Inlet wells.3 Worksheets 2 and 3 in Appendix IX-1 present
the detailed calculation of per-well fuel usage for baseline wells in offshore California and
coastal Cook Inlet, respectively. EPA used the volumes of drilling waste requiring onshore
disposal to calculate 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 calculated 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 a calculation 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. Based on
these line-items, the per-well baseline fuel usage rates for offshore California were calculated as
180 BOE for a DWD well and 143 BOE for a SWD well. For coastal Cook Inlet, the baseline
fuel usage rate for a SWD well was 285 BOE. The total annual baseline fuel usage rates for
these geographic areas, 2,121 BOE for offshore California and 285 BOE for Cook Inlet, were
calculated by multiplying the per-well rates by the corresponding numbers of baseline wells
listed in Table VIII-4.
Per-well baseline fuel usage rates (and all other NWQEI analyses) for baseline OBF wells
in the Gulf of Mexico are based on the estimate that 80% of these wells use land-disposal for
IX-7
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zero discharge and the remaining 20% use on-site injection to dispose of OBF cuttings. This
estimate is discussed further in sections VIII.3.1.3 and VIII.3.1.4. As in the per-well zero
discharge compliance cost analysis discussed in section VIII.3.2.1.1, the per-well zero discharge
environmental impacts for Gulf of Mexico wells were calculated as weighted averages reflecting
this distribution of zero discharge compliance methods. For the OBF model wells in the baseline
(SWD and SWE), per-well impacts were calculated for transport and disposal and for injection.
Then for each model well, a weighted average per-well impact was calculated as follows:
Baseline GOM OBF Well Impact = (0.8 x Per-Well Transportation & Disposal Impact) +
(0.2 x Per-Well Injection Impact)
Per-well baseline fuel usage rates for land disposal in the Gulf of Mexico were calculated using
the same line-items as described above for offshore California and coastal Cook Inlet wells. Per-
well baseline fuel usage rates for onsite injection are weighted averages of diesel usage rates and
natural gas usage rates, according to the estimate that 85% of wells use diesel and 15% use
natural gas as primary power sources in the Gulf of Mexico.4 Worksheet 1 in Appendix IX-1
shows the detailed per-well calculations for baseline wells in the Gulf of Mexico. EPA
calculated a per-well baseline fuel usage rate of 130 BOE for SWD wells and 186 BOE for SWE
wells. These per-well rates, multiplied by the corresponding numbers of baseline wells listed in
Table VIII-4 resulted in the total annual baseline fuel usage rate for the Gulf of Mexico existing
sources of 3,433 BOE. The sum of the baseline fuel usage rates or existing sources for the three
geographic areas is 5,839 BOE per year (Table IX-2).
3.1.2 BAT Discharge Option Energy Requirements
Energy consumption for the discharge option was calculated by identifying the equipment
and activities associated with the addition of a vibrating centrifuge device to reduce the retention
of the synthetic base fluid on drill cuttings from an average 11% to 7%, measured on a wet-
weight basis. A summary of the total discharge option energy requirements for existing sources
IX-8
-------
in the three geographic areas is presented in Table IX-2. The remainder of this section presents
the detailed calculations developed for each of the three geographic areas.
Per-well fuel usage rates were calculated for the four model wells in the Gulf of Mexico.
As stated in section IX.3.1.1, EPA estimated that 85% of Gulf of Mexico wells use diesel as their
primary source of fuel, and 15% use natural gas.4 Therefore, the per-well fuel usage rates for the
Gulf of Mexico are weighted averages of two distinct per-well rates based on diesel usage and
natural gas usage, respectively. These rates are identified in Worksheet 4 of Appendix IX-1 as
separate line-items under each model well. The per-well diesel usage rate was calculated by
multiplying the vibrating centrifuge operating time (equal to the number of drilling days) by the
consumption rate for diesel generators, estimated to be 6 gal/hr.5 An example diesel usage
calculation for a DWD model well is as follows:
(5.4 days) x (24 hr/day) x (6 gal/hr) = 777.6 gal diesel/well
(777.6 gal/well)/(42 gal/BOE) = 18.5 BOE/well
The per-well natural gas usage rate was calculated for gas turbines using an average heating
value of 1,050 Btu per standard cubic foot (scf) of natural gas and an average fuel consumption
of 10,000 Btu per horsepower-hour (hp-hr), or 9.5 (10,000/1,050) scf/hp-hr.6 Multiplying the
turbine consumption rate by the power demand of the vibrating centrifuge (20.5 kW = 27.49 hp)7
and the number of drilling days results in the per-well natural gas usage rate. An example natural
gas usage calculation for a DWD model well is:
(27.49 hp) x (5.4 days) x (24hrs/day) x (9.5 scf/hp-hr) = 33,845.7 scf natural gas/well
(33,845.7 scf/well) x (0.178BOE/1,000 scf) = 6.0 BOE/well
The total energy requirements for the 18 DWD wells drilled annually in the Gulf of Mexico are:
[(18.5 BOE/well) x (85% wells using diesel)+(6.0 BOE/well) x (15% wells using nat. gas)] x 18 DWD wells/yr =
299 BOE/yr for DWD wells
IX-9
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The same methodology shown in the above calculations was applied to the other three model
wells in the Gulf of Mexico and summed for the total energy requirement of 3,035 BOE per year.
Based on information regarding fuel use in offshore California, EPA estimated that all
shallow water wells use natural gas as fuel for generating electricity on the platforms.8 For deep
water wells, the estimate that 85% of the drilling operations use diesel and 15% use natural gas
was applied for the offshore California area. Worksheet 5 in Appendix IX-1 shows that the fuel
usage for the eleven (11) DWD wells in offshore California is 183 BOE per year, and 4 BOE per
year for the single SWD well drilled annually, for a total of 187 BOE per year for the area.
Only one SWD well is represented in the discharge option fuel usage analysis for Cook
Inlet, Alaska. Based on information from the Coastal Oil and Gas Rulemaking effort, EPA
estimated that the fuel used on Cook Inlet platforms for generating electricity is exclusively
natural gas.3 Thus, the previous example calculation of per-well natural gas usage was used for
coastal Cook Inlet. Work-sheet 6 in Appendix IX-1 shows that the per-well, and total discharge
option fuel usage for Cook Inlet is 4 BOE per year.
3.1.3 BAT Zero Discharge Option Energy Requirements
Energy consumption for compliance with the zero discharge option was calculated only
for Gulf of Mexico wells that currently discharge SBF cuttings, because all other wells are
currently at zero discharge and would not contribute impacts under this option. 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 for
land-based disposal; and 2) on-site injection. As stated in section IX.3.1.1, EPA estimated that
80%) of all Gulf of Mexico wells employing zero discharge technology use land-disposal for
waste cuttings, while 20% use onsite injection. Worksheets 7 and 8 of Appendix IX-1 list the
line-item activities for the land-disposal and onsite injection technologies, respectively.
Worksheet 9 presents the weighted average energy requirements base on this proportion of wells
IX-10
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using the corresponding zero discharge technology. The following sections present the detailed
estimates and data used to develop the per-well zero discharge fuel requirements associated with
these technologies.
3.1.3.1 Transportation and Onshore Disposal Energy Requirements
The per-well energy requirements associated with the transportation and onshore disposal
of drill cuttings varied between model wells and between geographic areas. Variations between
model wells were due to differences in the per-well waste volumes calculated for each model
well, as listed in Table VII-4. The model well waste volumes define the frequency of boat and
truck trips required to transport the waste. Variations between geographic areas were due to
differences in travel distances. Below are the assumptions and data that comprise the line-items
in Worksheets 7, 8, and 9 of Appendix IX-1 specific to the transportation and onshore disposal of
cuttings:
Supply Boats: Appendix VIII-1 presents the supply boat frequencies calculated for
each model well. The frequency of supply boats needed to haul drill cuttings from the
platform depends on the volume and rate of generation of the cuttings. Because the
waste generation rate is nearly 11 boxes per day (for all model wells) and the platform
storage capacity is 12 boxes (in all geographic areas), EPA determined that a supply
boat is available at the platform to receive the waste, independent of any requirements
proposed in this rule.
Based on information compiled in the Offshore Oil and Gas Rulemaking effort, EPA
determined the cuttings box capacity to be 25 bbl for the Gulf of Mexico and offshore
California areas.5 Based on similar information used in the Coastal Rulemaking
effort, an 8-bbl capacity was applied for the coastal Cook Inlet area.3 These capacities
determined the number of cuttings boxes needed to be transferred to the supply boats
and hauled to shore per model well and per geographic area.
Two types of supply boats provide service to the platform during drilling operations:
1) Dedicated supply boats are rented to provide service for special tasks. In the
NWQEI analysis, EPA estimated that dedicated supply boats would provide
IX-11
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service solely for offloading SBF or OBF cuttings. Dedicated supply boats are
used for all model wells in all areas. The dedicated supply boat capacity in both
the Gulf of Mexico and offshore California is 3,000 bbl (or 80 25-bbl cuttings
boxes).9 In coastal Cook Inlet, the capacity is 1,050 bbl (or 132 8-bbl cuttings
boxes).3 Except for Gulf of Mexico deep water exploratory model wells, the
waste generated from all other model wells in all geographic areas can be
transported to shore with the use of only one dedicated supply boat.
2) Regularly scheduled supply boats are contracted at the beginning of drilling
operations to arrive at the platform at regular intervals, bring supplies, and offload
no longer needed materials. EPA estimated that regularly scheduled supply boats
arrive at a drilling platform every four days.5 For the purposes of the NWQEI
analysis, EPA estimated that a regularly scheduled supply boat would be used
only after the capacity of a dedicated supply boat (see below) was reached and
additional cuttings still needed to be hauled to shore. This was only required in
the Gulf of Mexico for deep water exploratory model wells. The capacity of a
regularly scheduled supply boat in the Gulf of Mexico is 300 bbl (or twelve 25-
bbl cuttings boxes).5
Transit Fuel Consumption: Supply boats consume 130 gallons of diesel per hour
while in transit.10 Average supply boat speed is 11.5 miles per hour.5 The distance
the supply boat travels depends on whether the boat is a dedicated supply boat for
which the entire travel distance is used in the analysis or if it is a regularly scheduled
supply boat for which only the additional distance to travel to the disposal facility is
used. The roundtrip distance is dependent on the geographic area as follows (also, see
Appendix VIII-1):
Gulf of Mexico: 277 miles for dedicated supply boats; 77 miles for regularly
scheduled boats5
Offshore California: 200 miles for dedicated supply boats5
Cook Inlet, Alaska: 50 miles for dedicated supply boats3
Maneuvering Fuel Consumption: Supply boats maneuver at the platform for an
average of one hour per visit.11 The maneuvering fuel use factor is 15% of full
throttle fuel consumption (169 gal/hr), or 25.3 gallons of diesel per hour.11
Loading Fuel Consumption: Due to ocean current and wave action, boats must
maintain engines idling while unloading empty cuttings boxes and loading full boxes
at the platforms. An additional 1.6 hours is included to account for potential delays in
the transfer process.2 For dedicated supply boats, it is estimated that the boats are
available until either all of the waste is loaded or boat capacity is reached.
IX-12
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Auxiliary Electrical Generator: An auxiliary generator is needed for electrical power
when propulsion engines are shut down. This only occurs when the supply boats are
in port. The average in-port time for unloading drill cuttings, tank cleanout, and
demurrage is 24 hours per supply boat trip.5 Estimates of fuel requirements are based
on the auxiliary generator rating at 120 horsepower (hp), operating at 50% load (or 60
hp), and consuming 6 gallons of diesel per hour.5
Barges: Barges are used only in the Gulf of Mexico to haul waste from the transfer
station to the disposal site. The average round-trip distance is 100 miles.12 Barges
consume fuel at a rate of 24 gallons of diesel per hour and travel an average of 6 miles
per hour.2
Cranes: Cranes used to unload empty cuttings boxes and load full cuttings boxes at
the drill site and in port (or at the transfer station, as in the case of the Gulf of
Mexico) are diesel powered, require 170 horsepower operating at 80% load (or 136
hp), and consume 8.33 gallons of diesel per hour.5 Cranes make 10 lifts per hour.5
The total time to transfer the waste is dependent on the volume of drill cuttings as
determined by the number of full/empty cuttings boxes to be transferred and varies for
each model well as follows:
Gulf of Mexico and Offshore California (cuttings box capacity = 25 bbl)
Deep Water Development: (116 boxes to unload & load at drill site)/(10 lifts/hr)=l 1.6 hrs
Deep Water Exploratory: (258 boxes to unload & load at drill site)/(10 lifts/hr)=25.8 hrs
Shallow Water Development: (78 boxes to unload & load at drill site)/(10 lifts/hr)=7.8 hrs
Shallow Water Exploratory: (160 boxes to unload & load at drill site)/(10 lifts/hr)=16.0 hrs
Cook Inlet. Alaska (cuttings box capacity = 8 bbl)
Shallow Water Development: (240 boxes to unload & load at drill site)/(10 lifts/hr)=24.0 hrs
Trucks: Trucks transport drill cuttings from port to the disposal site. For the Gulf of
Mexico and Cook Inlet areas, truck fuel usage is assumed to be 4 miles per gallon3
and for California, 7 miles per gallon.13 The truck capacity and distance traveled vary
by geographic area as follows (see also Appendix VIII-1):
Gulf of Mexico: capacity =119 bbls5;
distance = 20 miles3
Offshore California: capacity = 50 bbls14;
distance = 300 miles (Appendix VIII-1)
Cook Inlet, Alaska: capacity = 64 bbls (Appendix VIII-1);
distance = 2,200 miles3
The number of truck trips depends on the volume of drill cuttings hauled per model
well and the capacity of the truck as listed above. Appendix VIII-1 presents in detail
the number of truck trips per model well and geographic area.
IX-13
-------
Land Disposal Equipment: Estimates regarding energy-consuming land disposal
equipment are as follows:
Wheel Tractor: Wheel tractors are used at the disposal facility for grading. One day
(8 hours) of tractor operation is required to grade the drill cuttings waste volume from
one well. The estimated fuel consumption rate for a wheel tractor is 1.67 gallons of
diesel per hour.5
Track-Type Dozer/Loader: A track-type dozer/loader is required at the facility for
waste spreading. Two days (16 hours) of dozer operation are required to spread drill
cuttings generated from one well. The estimated fuel consumption rate for a dozer is
22 gallons of diesel per hour.5
3.1.3.2 Onsite Grinding and Injection Energy Requirements
According to information available to EPA, zero discharge via on-site grinding and
injection is practiced by a growing number of operators in the Gulf of Mexico geographic area
(see section VII.5.6). The waste volume of cuttings injected varies per model well and is
presented in Table VII-4. Following are the identified equipment and activities required for
onsite injection and the corresponding power and fuel requirements.
Cuttings Transfer: Cuttings transfer equipment consists of one 100-hp vacuum
pump.15 The time of operation needed for transfer is equal to the length of time
required to drill the corresponding model well in hours. Drilling days are discussed in
section VIII.3.1.2.
Cuttings Grinding and Processing: The equipment used for grinding and
processing the drill cuttings consists of: one 75 hp grinding pump, two 10 hp mixing
pumps, two 10 hp vacuum pumps, and one 5 hp shale shaker motor.15 The total
power requirement is 120 hp. The time of operation for this equipment is equal to the
length of time required to drill each of the model wells in hours.
Cuttings Injection: One 600 hp injection pump rated at 2.5 barrels per minute is
used for cuttings injection.15
Fuel Requirements: EPA calculated fuel requirements for both diesel and natural gas
fuel sources according to the assumptions that 85% of Gulf of Mexico wells use
diesel and 15% use natural gas.4 For diesel generators, the fuel usage rate for all of
the grinding and injection equipment was 6 gallons of diesel/hour of operation.5 For
IX-14
-------
natural gas, the fuel requirements were calculated for gas turbines using an average
heating value of 1,050 Btu per standard cubic foot (scf) of natural gas and an average
fuel consumption of 10,000 Btu per horsepower-hour (hp-hr), or 9.5 (10,000/1,050)
scf/hp-hr.3
3.2 AIR EMISSIONS
The total air emissions for each of the regulatory options as presented in Table IX-1 were
calculated as the sum of the air emissions from each of the three geographic areas using the total
system energy utilization rate (horsepower-hours or miles traveled) and emission factors
developed for the various engines and fuels used. Table IX-3 presents the air emissions by
geographic area and model well for existing source wells. As in the Offshore Rulemaking effort,
EPA used emissions factors for uncontrolled sources. The term "uncontrolled" refers to the
emissions resulting from a source that does not utilize add-on control technologies to reduce the
emissions of specific pollutants. The use of "uncontrolled" emission factors provides
conservatively higher estimates of total emissions resulting from drill cuttings disposal. Table
IX-4 presents the uncontrolled emission factors for different types of diesel and natural gas
driven engines used to calculate air emissions from activities related to the discharge, onshore
disposal, or onsite injection of drill cuttings. For the discharge option, emission factors for either
diesel generators or natural gas turbines were used to calculate emissions associated with the
vibrating centrifuge. These emission factors were also used to calculate emissions associated
with the grinding and injection equipment. As mentioned above in section IX.3.1.1, 85% of the
Gulf of Mexico platforms utilize diesel as a fuel source and 15% utilize natural gas. This
proportion was applied to all of the model wells represented in the Gulf of Mexico and to deep
water development wells in offshore California. EPA assumed that the shallow water
development model wells in offshore California and coastal Cook Inlet use natural gas
exclusively (see section IX.3.1.2). Detailed calculations of the air emissions from each type of
engine used are presented in Appendix IX-1.
IX-15
-------
TABLE IX-3
SUMMARY BAT AIR EMISSIONS (tons/yr)
liiiscliiK* Tcchnoloiiv
Cull of Mexico
OITshoiv
California
Cook lulol.
Alaska
Tolal
DWD
nw i:
SWD
SWE
l)\\ 1)
SWI)
S\\ 1)
Baseline Emissions
Discharge at 11% retention
(current SBF users only)
0
0
0
0
NA
NA
NA
0
Zero Discharge
(current OBF users only)
NA
NA
27.0
20.9
34.7
1.9
2.1
86.6
Total Compliance Emissions
Discharge at 7% Option
1.2
8.7
1.2
1.4
0.8
0.0
0.0
13.3
Zero Discharge Option
39.2
259.5
21.6
18.3
NA
NA
NA
338.6
Reduction (Increase) in Emissions
Discharge at 7% Option
(1.2)
(8.7)
25.8
19.5
33.9
1.9
2.1
73.3
Zero Discharge Option
(39.2)
(259.5)
(21.6)
(18.3)
NA
NA
NA
(338.6)
EPA calculated the baseline and total compliance air emissions for both the discharge and
zero discharge options. The incremental air emissions for each of the options were determined
by subtracting the corresponding total compliance from the baseline (see Table IX-3).
3 .3 NSPS ENERGY REQUIREMENTS AND AIR EMISSIONS
As described in Chapter VIII, section 3.2, EPA projects that an estimated 19 new source
SBF wells will be drilled annually in the Gulf of Mexico, consisting of 18 deep water
IX-16
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TABLE IX-4
UNCONTROLLED EMISSION FACTORS FOR
DRILL CUTTINGS MANAGEMENT ACTIVITIES
CsiU'Sion
l-'.missittn l-'iicloi's
Units
NOx
THC
S02
CO
TSP
Supply Boats3
Transit
lb/gal
0.3917
0.168
0.02848b
0.0783
0.033
Maneuvering
lb/gal
0.4196
0.226
0.02848b
0.0598
0.033
Loading/U nloading
lb/gal
0.4196
0.226
0.02848b
0.0598
0.033
Demurrage
g/bhp-hr
14
1.12
0.931
3.03
1
Barge Transit3
lb/gal
0.3917
0.168
0.02848
0.0783
0.033
Supply Boat Cranes0
g/bhp-hr
14
1.12
0.931
3.03
1
Barge Cranes0
g/bhp-hr
14
1.12
0.931
3.03
1
Trucks'1
g/mile
11.23
2.49
NA
8.53
NA
Wheel Tractor6
lb/hr
1.269
0.188
0.09
3.59
0.136
Dozer/Loader6
lb/hr
0.827
0.098
0.076
0.201
0.058
Diesel Generate/
g/bhp-hr
14
1.12
0.931
3.03
1
Natural Gas Fired Turbines8
g/bhp-hr
1.3
0.18
0.002h
0.83
NA
3 Source: Table II-3.3, AP-42 Volume II, September 1985.16
b Based on assumed 0.20% sulfur content of fuel and fuel density of 7.12 lbs/gal (AP-42 Volume II, September 1985).16
c Source: Table 3.3-1, AP-42 Volume I, Supplement F, July 1993.17 Note: bhp is brake horsepower.
d Source: Table 1.7.1, AP-42 Volume II, September 1985.16
e Source: Table II-7.1, AP-42 Volume II, September 1985.16
f Source: Table 3.2-1, AP-42 Volume I, Supplement F, July 1993.17
8 Source: Table 3.3-1, AP-42 Volume I, January 1975.18 Note: bhp is brake horsepower.
h This factor depends on the sulfur content of the fuel used. For natural gas fired turbines, AP-42, 1976 (Table 3.2-1) gives
this emission factor based on assumed sulfur content of pipeline gas of 2,000 g/106 scf (AP-42 Vol. I, April 1976).6
NA = Not Applicable
IX-17
-------
TABLE IX-5
SUMMARY NSPS AIR EMISSIONS (tons/yr)
AND FUEL USAGE (BOE/yr)
liiisolino 1 cclinologt
Aii* Emissions
l-liol I Silfie
l)\\ 1)
l)\\ 1.
SWI)
SWE
Idlill
DWD
D\\ 1.
SWD
SWE
Idlill
Baseline Emissions
Discharge at 11% retention
0
NA
0
NA
0
NA
0
NA
0
Total Compliance Emissions
Discharge at 7% Option
1.23
NA
0.05
NA
1.28
300
NA
11
NA
311
Zero Discharge Option
39.2
NA
1.8
NA
41.0
2,802
NA
130
NA
2,932
Reduction (Increase) in Emissions
Discharge at 7% Option
(1.23)
NA
(0.05)
NA
(1.28)
(300)
NA
(11)
NA
(311)
Zero Discharge Option
(39.2)
NA
(1.8)
NA
(41.0)
(2,802)
NA
(130)
NA
(2,932)
development wells and one 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.
Table IX-5 summarizes the baseline, compliance, and incremental compliance energy
requirements (i.e., fuel usage) and air emissions for Gulf of Mexico new sources. The method
used to calculate the per-well impacts for new source wells are the same as for existing sources,
described above in sections IX.3.1 and IX.3.2. The per-well impacts were multiplied by the
corresponding number of wells (18 DWD, 1 SWD) and summed for each of the options.
Appendix VIH-2 includes three worksheets that present the baseline impacts (Worksheet 1), the
discharge option impacts (Worksheet 2), and the zero discharge option impacts (Worksheet 3) for
IX-18
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new source wells. The incremental compliance impacts were calculated by subtracting the
compliance impacts from the baseline impacts.
4.0 SOLID WASTE GENERATION
EPA does not expect that the regulatory options considered for this rule will change the
overall volume of solid waste generated. EPA does expect, however, that the rule would change
the characteristics of the waste generated. EPA projects that the regulatory options will affect
whether the wastes are discharged to water or disposed of onshore or injected onsite.
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.
Table IX-6 summarizes, for baseline, compliance, and incremental compliance levels for
existing and new sources, the amounts of solid waste disposed by onshore disposal and onsite
injection. Table VII-4 presents the model well data on which solid waste amounts were based.
For each model well, the total waste generated (in pounds) was multiplied by the number of wells
affected for the corresponding option and geographic area for the baseline and compliance
scenarios. EPA then calculated incremental compliance levels by subtracting compliance from
baseline solid waste values. For the discharge option, the negative values shown indicate the
amounts of waste that would not be disposed by zero-discharge technologies, as compared with
the baseline.
5.0 CONSUMPTIVE WATER USE
Neither of the two regulatory options is projected to affect consumptive water use.
IX-19
-------
TABLE IX-6
SOLID WASTE DISPOSED BY ZERO DISCHARGE TECHNOLOGIES FOR EXISTING AND NEW SOURCE WELLS
(pounds per year)
Option
Cull of Mexico
OITshore
( ;i 1 ilorni;i
Cook Inlet.
Alaska
Totals
Onshore
In jcclion
loliil
Onshore
Onshore
Onshore
In jcclion
Tolal
Existing Sources
Baseline Discharge
0
0
0
NA
NA
0
0
0
Baseline Zero Discharge
17,056,680
4,264,170
21,320,850
11,844,255
671,214
29,572,149
4,264,170
33,836,319
Compliance Discharge
0
0
0
0
0
0
0
0
Compliance Zero Discharge
131,928,610
32,982,152
164,910,762
0
0
131,928,610
32,982,152
164,910,762
Incremental Discharge
(17,056,680)
(4,264,170)
(21,320,850)
(11,844,255)
(671,214)
(29,572,149)
(4,264,170)
(33,836,319)
Incremental Zero Discharge
131,928,610
32,982,152
164,910,762
0
0
131,928,610
32,982,152
164,910,762
New Sources
Baseline Discharge
0
0
0
NA
NA
0
0
0
Baseline Zero Discharge
NA
NA
NA
NA
NA
NA
NA
NA
Compliance Discharge
0
0
0
NA
NA
0
0
0
Compliance Zero Discharge
10,478,066
2,619,517
13,097,583
NA
NA
10,478,066
2,619,517
13,097,583
Incremental Discharge
0
0
0
NA
NA
0
0
0
Incremental Zero Discharge
10,478,066
2,619,517
13,097,583
NA
NA
10,478,066
2,619,517
13,097,583
-------
6.0 OTHER FACTORS
6.1 IMPACT OF MARINE TRAFFIC
EPA estimated the changes in vessel traffic that would result from the implementation of
either the discharge or the zero discharge option using the same methodology as the energy
consumption and air emissions impacts analyses described above. Appendix VIII-1 presents the
source data and calculations for the per-well estimate of boat trips required for compliance.
To comply with the zero discharge option, EPA estimated that the 113 existing and new
source wells in the Gulf of Mexico currently drilled with SBF would implement zero discharge
technologies. Based on the assumption that 80% of these wells would transport waste drill
cuttings to shore and each well requires one dedicated supply boat, an estimated total of 91 boat
trips per year would be required. No additional boat trips would be required in offshore
California and coastal Cook Inlet because these geographic areas are currently at zero discharge
of SBF-cuttings.
Under the discharge option, 23 GOM wells, the 12 offshore 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 onsite; 12 trips for the 12 wells in offshore California; and one 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% 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% in the Gulf of Mexico.
IX-21
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6.2 SAFETY
EPA investigated the possibility of an increase in injuries and fatalities that would occur
as a result of hauling additional volumes of drilling waste to shore under the zero discharge
option. EPA reviewed data regarding personnel casualties occurring on mobile offshore drilling
units (MODUs) and offshore supply vessels (OSV).19 One of the conclusions of this evaluation
is that since the number of increased crane handling events in the Gulf of Mexico is very small in
relation to the total number of handling operations occurring at drilling and production sites, no
discernable increase in casualties attributable to onshore disposal of drill cuttings is anticipated.
In a document submitted by the Department of Energy, increased safety risks under a zero
discharge option is a stated concern but the data do not clearly establish a correlation between
injury incidence and onshore disposal of drill cuttings.20
IX-22
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7,
1
2
3
4
5
6
7
8
9
1'
1
REFERENCES
Mason, T. Avanti Corporation, Memorandum regarding "Conversion Factor to BOE
(Barrels of Oil Equivalents) for Natural Gas and Diesel Fuel," July 12, 1996.
U.S. Environmental Protection Agency, Development Document for Effluent Limitations
Guidelines and New Source Performance Standards for the Offshore Subcategory of the
Oil and Gas Extraction Point Source Category, Final, EPA 821-R-93-003, January 1993.
U.S. Environmental Protection Agency, Development Document for Final Effluent
Limitations Guidelines and Standards for the Coastal Subcategory of the Oil and Gas
Extraction Point Source Category, EPA 821-R-96-023, October 1996.
Daly, Joseph, U.S. EPA, Memorandum regarding "Market Share of Respondents to
Technical Questions, August 17, 1998.
Carriere, J. and E. Lee, Walk, Haydel and Associates, Inc., "Water-Based Drilling Fluids
and Cuttings Disposal Study Update," Offshore Effluent Guidelines Comments Research
Fund Administered by Liskow and Lewis, January 1989.
U.S. EPA, "Compilation of Air Pollutant Emission Factors," AP-42, Volume I, April
1976.
Mclntyre, Jamie, Avanti Corporation, Memorandum to Joseph Daly, U.S. EPA, regarding
"Summary of December 2 Meeting with David Wood of Mud Recovery Systems,"
December 18, 1997.
Veil, John A., Argonne National Laboratory, Washington, D.C., "Data Summary of
Offshore Drilling Waste Disposal Practices," prepared for the U.S. Environmental
Protection Agency, Engineering and Analysis Division, and the U.S. Department of
Energy, Office of Fossil Energy, November 1998.
Kennedy, Kerri, The Pechan-Avanti Group, Telecommunications Report on conversation
with John Belsome, Seabulk Offshore Ltd., regarding "Offshore supply boat costs and
specifications," June 3, 1998.
U.S. EPA, "Trip Report to Campbell Wells Landfarms and Transfer Stations in
Louisiana," June 30, 1992.
Jacobs Engineering Group, "Air Quality Impact of Proposed Lease Sale No. 95,"
prepared for U.S. Department of the Interior, Minerals Management Service, June 1989.
IX-23
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12. Sunda, John, SAIC, Memorandum to Allison Wiedeman, U.S. EPA, regarding "The
assumptions used in the development of the cost of commercial disposal of produced
water using barge transportation," March 10, 1994.
13. Montgomery, Richard, The Pechan-Avanti Group, Telecommunication Report on
conversation with Shane Morgan, Ecology Control Incorporated, regarding "costs
associated with land and water transport of drill cuttings and drilling fluids for offshore
oil platforms operating off the California coast," May 9, 1998.
14. Mclntyre, Jamie, The Pechan-Avanti Group, Telecommunications Report on conversation
with Darron Stankey, McKittrick Solid Waste Disposal Facility, regarding "California
Prices for Land Disposal of Drilling Wastes," October 16,1998.
15. Kennedy, Kerri, The Pechan-Avanti Group, Telecommunications Report on conversation
with personnel at Apollo Services regarding "Detailed Information Regarding Apollo's
Cuttings Injection System," July 9, 1998.
16. U.S. EPA, "Compilation of Air Pollutant Emission Factors," AP-42, Volume n,
September 1985.
17. U.S. EPA, "Compilation of Air Pollutant Emission Factors," AP-42, Volume I,
Supplement F, July 1993.
18. U.S. EPA, "Compilation of Air Pollutant Emission Factors," AP-42, Volume I, January
1975.
19. SAIC, "Evaluation of Personnel Injury/Casualty Data Associated with Drilling Activity
for the Offshore Oil and Gas Industry," prepared for U.S. EPA, Engineering and Analysis
Division, January 11, 1992.
20. Meinhold, Anne, "Framework for a Comparative Environmental Assessment of Drilling
Fluids," prepared for the U.S. Department of Energy, National Petroleum Technology
Office, November 1998.
IX-24
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CHAPTER X
OPTIONS SELECTION RATIONALE
1.0 INTRODUCTION
This chapter presents the options EPA has selected for control of the SBF and SBF-
cuttings wastestreams. A discussion of the rationale for option selection is also included.
2.0 REGULATORY OPTIONS CONSIDERED FOR SBFs NOT ASSOCIATED WITH
DRILL CUTTINGS
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.
Because of the value of the SBFs, this option is already current industry practice and thus is
technically available. Also, because this option is current practice, there are no costs associated
with this regulatory option, and thus it is economically achievable and has no non-water quality
environmental impacts.
3.0 REGULATORY OPTIONS CONSIDERED FOR SBFs ASSOCIATED WITH
DRILL CUTTINGS
EPA considered two options for the 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 this proposal. This discharge option controls under BAT and NSPS the
stock base fluid through limitations on PAH content, sediment toxicity, and biodegradation rate,
X-l
-------
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 this 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 of OBF-cuttings annually 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. 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. EPA also believes that the
discharge option would result in the generation of less harmful drill cuttings. 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.
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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.
3.1 BPT TECHNOLOGY OPTIONS CONSIDERED AND SELECTED
The BPT effluent limitations proposed 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 nonconventional and toxic pollutants, EPA saw no
reason to expend time and resources to develop a different, less restrictive BPT limit.
X-3
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3.2
BCT TECHNOLOGY OPTIONS CONSIDERED AND SELECTED
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.
3.3 BAT TECHNOLOGY OPTIONS CONSIDERED AND SELECTED
EPA proposes BAT effluent limitations for the cuttings contaminated with SBFs. The
BAT effluent limitations proposed 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 proposed BAT limitations are as follows:
¦ Stock Limitations on Base Fluids:
o Maximum PAH content 10 ppm (wt. based on phenanthrene/wt. base fluid).
o Minimum rate of biodegradation (biodegradation equal to or faster than C16 - C18
internal olefin by solid phase test).
o Maximum sediment toxicity (as toxic or less toxic than C16 - C18 internal olefin by
10-day sediment toxicity test).
X-4
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¦ Discharge Limitations on Cuttings Contaminated with SBFs:
o Maximum formation oil contamination (95 percent of representative formation
oils failing 1 percent by volume in drilling fluid). (BAT/NSPS)
o Maximum well-average retention of SBF on cuttings (10.2 percent base fluid on
wet cuttings). (BAT/NSPS)
3.3.1 Stock Base Fluid Technical Availability and Economic Achievability
The stock base fluid limitations 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.
EPA finds that the proposed stock base fluid controls are economically achievable. Since
these base fluids are commonly used in the Gulf of Mexico, EPA anticipates no additional costs
to industry as a result of these stock limitations other than monitoring (testing and certification)
costs. EPA anticipates that any costs to comply with the stock limitations due to compliance
testing with be minimal because EPA intends that the monitoring be performed only once per
production batch for PAH content, and only once per year per trade name for sediment toxicity
and biodegradation rate. Further, EPA anticipates that these costs will be absorbed by the
supplier, but are not likely to significantly impact the pricing of the base fluids.
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 analysis presented in Chapter VIII supports this claim. Costs for SBFs and
OBFs using various base fluids are presented in Chapter VII.
X-5
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Pursuant to EPA's further research into sediment toxicity and biodegradation, EPA may
propose limits for the final rule that are different than the proposed limits. 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.
3.3.2 Discharge Limitations Technical Availability and Economic Achievability
3.3.2.1 Formation Oil Contamination of SBF-Cuttings
The 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.1'2
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
X-6
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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.3 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.
3.3.2.2 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 Chapter VII of this document. EPA
also considered fuel use, safety, and other considerations.
EPA has selected the vibrating centrifuge, treating drill cuttings from the primary shale
shaker, as the model technology on which to base the limitation of base fluid on cuttings. 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. EPA has analyzed the performance of the vibrating centrifuge, and reported the
findings.4,5 In addition, EPA was invited by an operator in the Gulf of Mexico to observe the
X-7
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operation of the vibrating centrifuge. 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 proposed limitation for retention of SBF is 10.2 percent base fluid on wet cuttings
(wt./wt.), 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.4'5 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.
X-8
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The model technology that EPA identified has two wastestreams: 1) cuttings from the
primary shale shaker feeding into the vibrating centrifuge, estimated to comprise 80 percent of
the cuttings by weight, and 2) cuttings from the secondary shale shaker, estimated to comprise
the remaining 20 percent of the cuttings. While the proposed limitation is based on this model
technology4, EPA does not intend to prescribe that this technology be used. The two
wastestreams are an artifact of the model technology, so they may not always exist. EPA realizes
that it may be possible for operators to treat all drill cuttings as a single wastestream. In fact,
such processes are used in the North Sea with the vibrating centrifuge. Therefore, EPA did not
want to implicitly prescribe that the two wastestreams of the model technology be used by
maintaining limits on each wastestream separately. For this reason EPA has averaged the model
limits, based on an estimate from industry representatives of the relative volume (80/20) of the
two wastestreams.6 EPA believes that the proposed limits can be met at all times by: (1)
providing better attention to the operation of the technology, (2) keeping track of the average
volume-weighted retention as the well is being drilled and (3) barging to shore or injecting a
portion of the cuttings wastestream at some reasonable point prior to exceeding the limit, if this
is ever necessary.
In the North Sea, the observed performance for the primary shale shakers used in series
before the vibrating centrifuge was a volume-weighted average retention of 12.4 percent. This
retention is 1.9 percentage points higher than the average volume-weighted retention of 10.5
percent observed for the primary shale shakers of the 21 wells in the Gulf of Mexico. This
suggests that the vibrating centrifuge is likely to perform better in the Gulf of Mexico than in the
North Sea, since the cuttings entering already have lower retention values. In the North Sea, all
cuttings came from primary shale shakers, absent the use of secondary shale shakers, thereby
eliminating the separate wastestream of cuttings from the secondary shale shakers. Elimination
of the finer cuttings from the secondary shale shakers may also be possible in the Gulf of
Mexico. Based on current information, however, EPA assumes that in Gulf of Mexico
operations a portion of the cuttings discharges will be from the secondary shale shakers.
X-9
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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, as shown by the detailed calculations presented in Chapter
VIII of this 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.7 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.
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3.4
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 level
of control for new sources.8 Therefore, EPA is proposing that NSPS be established equivalent to
BPT for conventional pollutants and BAT for priority and nonconventional pollutants.
3.5 TABLES OF PROPOSED LIMITATIONS
The proposed regulation would amend the tables of 40 CFR Part 435, Subparts A (for
offshore) and D (for coastal) in order to incorporate the new requirements for SBFs. The current
tables do not specify drilling fluid type. This was appropriate when only WBFs and OBFs
existed, because the current test methods were developed for WBFs, and the OBFs either failed
the discharge compliance tests or were prohibited from discharge if they contained diesel oil.
SBFs fall into the more general category of non-aqueous drilling fluids. The more general
category of non-aqueous drilling fluids is used in the regulatory text because what is germane for
the discharge is not whether the water immiscible base fluid are termed "synthetic," but rather the
base fluids' compliance with the performance limitations based on PAH content, sediment
toxicity, and biodegradation rate.
X-ll
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The tables shown below apply to both the offshore and coastal subcategories. For BAT
and NSPS, the proposed limitations apply only where the discharge of drilling fluids and cuttings
is currently allowed. In the offshore subcategory, this includes facilities located beyond 3 miles
from shore, except in Alaska which has no three mile restriction. In the coastal subcategory, this
includes facilities located in Cook Inlet, Alaska. While the requirements for WBFs have not
changed, they are included in these tables to show how the applicability of the current guidelines
is being specified for WBFs only. See Chapter in of this document for an explanation of where
discharge is currently allowed and detailed definitions of the various drilling fluid types. Tables
X-l through X-3 show the limitations proposed under each option for the wastestream of drilling
fluids and drill cuttings.
TABLE X-l
PROPOSED BPT AND BCT EFFLUENT LIMITATIONS
Waste Source
Pollutant Parameter
BPT/BCT Effluent Limitation
Water-based2
Drilling fluids
Free oil
no discharge1
Drill cuttings
Free oil
no discharge1
Non-aqueous2
Drilling fluids
no discharge
Drill cuttings
Free oil
no discharge1
1 No discharge of free oil as determined by the static sheen test
2 BCT Limitations in the Coastal Subcategory also include dewatering effluent, at the same
level of control as drilling fluids.
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TABLE X-2
PROPOSED BAT EFFLUENT LIMITATIONS
Waste Source
Pollutant Parameter
ISAT Kt'tluent Limitation
Water-based drilling fluids and drill
cuttings1
SPP Toxicity
Minimum 96-hour LC50 of the SPP shall be
3% by volume2
Free oil
No discharge3
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 fluids1
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 Hydrocarbons (PAH)
Maximum 10 ppm wt. PAH based on
phenanthrene/wt. of stock base fluid5
Sediment Toxicity
10-day LC50 of stock base fluid minus 10-
day LC50 of C16-C18 internal olefin shall not
be less than zero6
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
zero7
Discharge Limitations
Diesel oil
No discharge
Formation Oil
No discharge8
Base fluid retained on cuttings.
Maximum weighted average for well shall
be 10.2 percent.9,10
BCT Limitations in the Coastal Subcategory also include dewatering effluent, at the same level of control as drilling fluids.
As determined by the suspended particulate phase toxicity test 40 CFR 435, Subpart A, Appendix 2.
As determined by the static sheen test 40 CFR 435, Subpart A, Appendix 1.
Proposed: 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)].
Proposed: As determined by ASTM El367-92: 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 40 CFR 435, Subpart A,
Appendix 3.
Proposed: As determined by the biodegradation test 40 CFR 435, Subpart A, Appendix 4.
Proposed: As determined by the GC/MS baseline and assurance method (40 CFR 435, Subpart A, Appendix 5), and by the RPE
method applied to drilling fluid removed from cuttings at primary shale shakers (40 CFR 435, Subpart A, Appendix 6).
Proposed: Maximum permissible retention of base fluid on wet cuttings averaged over drill intervals using non-aqueous drilling fluids
as determined by retort method (40 CFR 435, Subpart A, Appendix 7).
Corrected limitation would be 9.42 percent (Refs. 4 and 5).
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TABLE X-3
PROPOSED NSPS EFFLUENT LIMITATIONS
Waste Source
Pollutant I';ir;imetcr
NSl'S I'.t'tlucnt Limitation
Water-based drilling fluids and drill
cuttings1
SPP Toxicity
Minimum 96-hour LC50 of the SPP shall be
3% by volume2
Free oil
No discharge3
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 fluids1
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 Hydrocarbons (PAH)
Maximum 10 ppm wt. PAH based on
phenanthrene/wt. of stock base fluid5
Sediment Toxicity
10-day LC50 of stock base fluid minus 10-
day LC50 of C16-C18 internal olefin shall not
be less than zero6
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
zero7
Discharge Limitations
Diesel oil
No discharge
Free Oil
No Discharge3
Formation Oil
No discharge8
Base fluid retained on cuttings.
Maximum weighted average for well shall
be 10.2 percent.9,10
BCT Limitations in the Coastal Subcategory also include dewatering effluent, at the same level of control as drilling fluids.
As determined by the suspended particulate phase toxicity test 40 CFR 435, Subpart A, Appendix 2.
As determined by the static sheen test 40 CFR 435, Subpart A,Appendix 1.
Proposed: 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)].
Proposed: As determined by ASTM El367-92: 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 40 CFR 435, Subpart A,
Appendix 3.
Proposed: As determined by the biodegradation test 40 CFR 435, Subpart A, Appendix 4.
Proposed: As determined by the GC/MS baseline and assurance method (40 CFR 435, Subpart A, Appendix 5), and by the RPE
method applied to drilling fluid removed from cuttings at primary shale shakers (40 CFR 435, Subpart A, Appendix 6).
Proposed: Maximum permissible retention of base fluid on wet cuttings averaged over drill intervals using non-aqueous drilling fluids
as determined by retort method (40 CFR 435, Subpart A, Appendix 7).
Corrected limitation would be 9.42 percent (Refs. 4 and 5).
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4.0 REFERENCES
1. Uhler, A.D., J.A. Seavey, and G.S. Durell, Battelle, "Laboratory Evaluation of Static
Sheen Replacements: RPE Method (Final Draft Report)," plus addendum, November 16,
1998, with cover letter from Robert Moran, National Ocean Industries Association, to
Joseph Daly, U.S. EPA, November 16, 1998.
2. Uhler, A.D., J.A. Seavey, and G.S. Durell, Battelle, "Laboratory Evaluation of Static
Sheen Replacements: GC/MS Method (Draft Report)," November 16, 1998, with cover
letter from Robert Moran, National Ocean Industries Association, to Joseph Daly, U.S.
EPA, November 19, 1998.
3. Daly, Joseph, U.S. EPA, Memorandum regarding "Contamination of Synthetic-Based
Drilling Fluid (SBF) with Crude Oil," January 14, 1999.
4. White, Charles E., and Henry D. Kahn, U.S. EPA, Statistics Analysis Section,
Memorandum to Joseph Daly, U.S. EPA, Energy Branch, regarding "Current
Performance, when using Synthetic-Based Drilling Fluids, for Primary Shakers,
Secondary Shakers, and Vibrating Centrifuge and Model Limits for Percent Retention of
Base Fluids on Cuttings for Secondary Shakers and Vibrating Centrifuge," January 29,
1999.
5. Daly, Joseph, U.S. EPA, Memorandum regarding "Correction to the Regulatory Limits
for Retention of Base Fluid on Cuttings as Presented in the Preamble to the SBF
Proposed Rule from 10.2 to 9.42 Percent," January 29, 1999.
6. Annis, Max R., "Procedures for Sampling and Testing Cuttings Discharged While
Drilling with Synthetic-Based Muds," prepared for the American Petroleum Institute
(API) ad hoc Retention on Cuttings Work Group under the API Production Effluent
Guidelines Task Force, August 19, 1998.
7. Daly, Joseph, U.S. EPA, Memorandum regarding "Cost Savings Resulting from
Increased Recovery of SBF from Drill Cuttings," February 1, 1999.
8. U.S. EPA, 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, February 1999.
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CHAPTER XI
BEST MANAGEMENT PRACTICES
Sections 304(e) and 402(a) of the Act authorizes the Administrator to prescribe "best
management practices" (BMPs) to control "plant site runoff, spillage or leaks, sludge or waste
disposal, and drainage from raw material storage." Section 402(a)(1) and NPDES regulation (40
CFR 122) also provide for best management practices to control or abate the discharge of
pollutants when numeric limitations are infeasible. 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.
The proposed rule for SBFs does not establish BMPs. However, 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
has solicited comments from industry indicating the types of BMPs that would minimize or
prevent SBF spills. EPA has also solicited 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.
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GLOSSARY AND ABBREVIATIONS
Act: The Clean Water Act.
ADEC: Alaska Department of Environmental
Conservation.
Agency: The U.S. Environmental Protection
Agency.
Annular Injection: Injection of fluids into
the space between the drill string or
production tubing and the open hole or
well casing.
Annulus or Annular Space: The space
between the drill string or casing and the
wall of the hole or casing.
AOGA: Alaskan Oil and Gas Association.
API: American Petroleum Institute.
ASTM: American Society of Testing and
Materials.
Barite: Barium sulfate. An additive used to
increase drilling fluid density.
Barrel (bbl): 42 United States gallons at 60
degrees Fahrenheit.
BAT: The best available technology
economically achievable, under Section
304(b)(2)(B) of the Clean Water Act.
BADCT: The best available demonstrated
control technology, for new sources under
Section 306 of the Clean Water Act.
BCT: The best conventional pollutant control
technology, under Section 301(b)(2)(E) of
the Clean Water Act.
BMP: Best Management Practices under
Section 304(e) of the Clean Water Act.
BOD: Biochemical oxygen demand.
BOE: Barrels of oil equivalent. Used to put
oil production and gas production on a
comparable volume basis. 1 BOE = 42
gallons of diesel and 1,000 scf of natural
gas = 0.178 BOE.
bpd: Barrels per day.
BP J: Best Professional Judgment.
BPT: The best practicable control technology
currently available, under section 304(b)(1)
of the Clean Water Act.
bpy: Barrels per year.
Brine: Water saturated with or containing
high concentrations of salts including
sodium chloride, calcium chloride, zinc
chloride, calcium nitrate, etc. Produced
water is often called brine.
BTU: British Thermal Unit.
Casing: Large steel pipe used to "seal off or
"shut out" water and prevent caving of
loose gravel formations when drilling a
well. When the casings are set and
cemented, drilling continues through and
below the casing with a smaller bit. The
overall length of this casing is called the
G-1
-------
casing string. More than one string inside
the other may be used in drilling the same
well.
CBI: Confidential Business Information.
Centrifuge: Filtration equipment that uses
centrifugal force to separate substances of
varying densities. A centrifuge is capable
of spinning substances at high speeds to
obtain high centrifugal forces. Also called
the shake-out or grind-out machine.
cfd: cubic feet per day
CFR: Code of Federal Regulations.
Clean Water Act (CWA): The Federal
Water Pollution Control Act of 1972 (33
U.S.C. 1251 et seq.), as amended by the
Clean Water Act of 1977 (Pub. L. 95-217)
and the Water Quality Act of 1987 (Pub. L.
100-4).
CO: Carbon Monoxide.
Completion: Activities undertaken to finish
work on a well and bring it to productive
status.
Condensate: Liquid hydrocarbons which are
in the gaseous state under reservoir
conditions but which become liquid either
in passage up the hole or in the surface
equipment.
Connate Water: Water that was laid down
and entrapped with sedimentary deposits as
distinguished from migratory waters that
have flowed into deposits after they were
laid down.
Conventional Pollutants: Constituents of
wastewater as determined by Section
304(a)(4) of the Act, including, but not
limited to, pollutants classified as
biochemical oxygen demanding, suspended
solids, oil and grease, fecal coliform, and
pH.
Deck Drainage: All wastes resulting from
platform washings, deck washings, spills,
rainwater, and runoff from curbs, gutters,
and drains, including drip pans and wash
areas.
Depth Interval: Interval at which a drilling
fluid system is introduced and used, such as
from 2,200 to 2,800 ft.
Development Facility: Any fixed or mobile
structure addressed by this document that
is engaged in the drilling of potentially
productive wells.
Dewatering Effluent: The wastewater
derived from dewatering drill cuttings.
Diesel Oil: The grade of distillate fuel oil, as
specified in the American Society for
Testing and Materials' Standard
Specification D975-81.
Disposal Well: A well through which water
(usually salt water) is returned to
subsurface formations.
DOE: Department of Energy
Domestic Waste: Materials discharged from
sinks, showers, laundries, and galleys
located within facilities addressed by this
document. Included with these wastes are
safety shower and eye wash stations, hand
wash stations, and fish cleaning stations.
DMR: Discharge Monitoring Report.
G-2
-------
Drill Cuttings: Particles generated by drilling
into subsurface geologic formations and
carried to the surface with the drilling fluid.
Drill Pipe: Special pipe designed to withstand
the torsion and tension loads encountered
in drilling.
Drilling Fluid: The circulating fluid (mud)
used in the rotary drilling of wells to clean
and condition the hole and to
counterbalance formation pressure. A
water-based drilling fluid is the con-
ventional drilling fluid in which water is
the continuous phase and the suspending
medium for solids, whether or not oil is
present. An oil-base drilling fluid has
diesel, crude, or some other oil as its
continuous phase with water as the
dispersed phase.
Drilling Fluid System: System consisting
primarily of mud storage tanks or pits, mud
pumps, stand pipe, kelly hose, kelly, drill
string, well annulus, mud return flowline,
and solids separation equipment. The
primary function of circulating the drilling
fluid is to lubricate the drill bit, and to carry
drill cuttings rock fragments from the
bottom of the hole to the surface where
they are separated out.
DWD: Deep-water development well.
DWE: Deep-water exploratory well.
Emulsion: A stable heterogenous mixture of
two or more liquids (which are not
normally dissolved in each other held in
suspension or dispersion, one in the other,
by mechanical agitation or, more
frequently, by the presence of small
amounts of substances known as
emulsifiers. Emulsions may be oil-in-
water, or water-in-oil.
Enhanced Mineral Oil-Based Drilling
Fluid: A drilling fluid that 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.
ENR-CCI: Engineering News Record-Con-
struction Indices.
EPA (or U.S. EPA): U.S. Environmental
Protection Agency.
Exploratory Well: A well drilled either in
search of an as-yet-undiscovered pool of oil
or gas (a wildcat well) or to extend greatly
the limits of a known pool. It involves a
relatively high degree of risk. Exploratory
wells may be classified as (1) wildcat,
drilled in an unproven area; (2) field
extension or step-out, drilled in an
unproven area to extend the proved limits
of a field; or (3) deep test, drilled within a
field area but to unproven deeper zones.
Facility: See Produced Water Separation/
Treatment Facility.
Field: A geographical area in which a number
of oil or gas wells produce hydrocarbons
from an underground reservoir. A field
may refer to surface area only or to
underground productive formations as well.
A single field may have several separate
reservoirs at varying depths.
Flocculation: The combination or
aggregation of suspended solid particles in
such a way that they form small clumps or
tufts resembling wool.
Footprint: The square footage covered by
various production equipment.
G-3
-------
Formation: Various subsurface geological
strata.
Formation Damage: Damage to the pro-
ductivity of a well resulting from invasion
of drilling fluid particles or other
substances into the formation.
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.
9Ph: Gallons per hour.
gpm: Gallons per minute.
hp: Horsepower.
Indirect Discharger: A facility that
introduces wastewater into a publically
owned treatment works.
Injection Well: A well through which fluids
are injected into an underground stratum to
increase reservoir pressure and to displace
oil, or for disposal of produced water and
other wastes.
Internal Olefin (10): A series of isomeric
forms of C16 and C18 alkenes.
kW: Kilowatt.
LC50: The concentration of a test material that
is lethal to 50% of the test organisms in a
bioassay.
LDEQ: Louisiana Department of
Environmental Quality.
Lease: A legal document executed between a
landowner, as lessor, and a company or
individual as lessee, that grants the right to
exploit the premises for minerals; the
instrument that creates a leasehold or
working interest in minerals.
Linear Alpha Olefin (LAO): A series of
isomeric forms of C14 and C16 monoenes.
m: Meters.
mcf: Thousand cubic feet.
|jg/l: Micrograms per liter.
mg/l: Milligrams per liter.
MM: Million.
MMcfd: Million cubic feet per day.
MMS: Department of Interior Minerals
Management Service.
MMscf: Million standard cubic feet.
Mscf: Thousand standard cubic feet.
Mud: Common term for drilling fluid.
Mud Pit: A steel or earthen tank which is part
of the surface drilling fluid system.
Mud Pump: A reciprocating, high pressure
pump used for circulating drilling fluid.
NOx: Nitrogen Oxide.
Non-Aqueous Drilling Fluid: A drilling
fluid in which the continuous phase is a
water-immiscible fluid such as an
G-4
-------
oleaginous material (e.g., mineral oil,
enhanced mineral oil, paraffinic oil, or
synthetic material such as olefins and
vegetable esters).
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: National Pollutant Discharge
Elimination System.
NPDES Permit: A National Pollutant
Discharge Elimination System permit
issued under Section 402 of the Act.
NRDC: Natural Resources Defence Council,
Incorporated.
NSPS: New source performance standards
under Section 306 of the Act.
NWQEI: Non-water quality environmental
impact.
O&M: Operating and maintenance.
OCS: Offshore Continental Shelf.
Oil-Based Drilling Fluid (OBF): A drilling
fluid that 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.
Oil-based Pill: Mineral or diesel oil injected
into the mud circulation system as a slug,
for the purpose of freeing stuck pipe.
Offshore Development Document: U.S.
EPA, Development Document for Effluent
Limitations Guidelines and New Source
Performance Standards for the Offshore
Subcategory of the Oil and Gas Extraction
Point Source Category, Final, EPA 821-R-
93-003, January 1993.
Operator: The person or company
responsible for operating, maintaining, and
repairing oil and gas production equipment
in a field; the operator is also responsible
for maintaining accurate records of the
amount of oil or gas sold, and for reporting
production information to state authorities.
PAH: Polynuclear Aromatic Hydrocarbon.
Poly Alpha Olefin (PAO): A mix mainly
comprised of a hydrogenated decene dimer
C20H62 (95%), with lesser amounts of C30H62
(4.8%) and C10H22 (0.2%).
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 Act.
Produced Sand: Slurried particles used in
hydraulic fracturing and the accumulated
formation sands and other particles that can
be generated during production. This
includes desander discharge from the pro-
duced water waste stream and blowdown of
the water phase from the produced water
treating system.
Produced Water: Water (brine) brought up
from the hydrocarbon-bearing strata with
the produced oil and gas. This includes
G-5
-------
brines trapped with the oil and gas in the
formation, injection water, and any
chemicals added downhole or during the
oil/water separation process.
Produced Water Separation/Treatment
Facilities: A "facility" is any group of
tanks, pits, or other apparatus that can be
distinguished by location, e.g., on-site/off-
site or wetland/upland and/or by disposal
stream (any produced water stream that is
not recombined with other produced water
streams for further treatment or disposal,
but is further treated and/or disposed of
separately). The facility may thus be, for
example, an on-site tank battery, an off-site
gathering center, or a commercial disposal
operation. The primary focus is on treat-
ment produced water, not on treating oil.
Production Facility: Any fixed or mobile
facility that is used for active recovery of
hydrocarbons from producing formations.
The production facility begins operations
with the completion phase.
PSES: Pretreatment Standards for Existing
Sources of indirect dischargers, under
Section 307(b) of the Act.
psi: pounds per square inch.
psig: pounds per square inch gauge.
PSNS: Pretreatment Standards for New
Sources of indirect dischargers, under
Section 307(b) and (c) of the Act.
RCRA: Resource Conservation and Recovery
Act (Pub. L. 94-580) of 1976.
Amendments to Solid Waste Disposal Act.
Recompletion: When additional drilling
occurs at an existing well after the initial
completion of the well and drilling waste is
generated.
Reservoir: Each separate, unconnected body
of a producing formation.
Rotary Drilling: The method of drilling
wells that depends on the rotation of a
column of drill pipe with a bit at the
bottom. A fluid is circulated to remove the
cuttings.
RPE: Reverse Phase Extraction.
RRC: Railroad Commission of Texas.
Sanitary Waste: Human body waste
discharged from toilets and urinals located
within facilities addressed by this
document.
scf: standard cubic feet.
Shut In: To close valves on a well so that it
stops producing; said of a well on which
the valves are closed.
SIC: Standard Industrial Classification.
S02: Sulfur Dioxide.
SPP: Suspended Particulate Phase.
SWD: Shallow -water development well.
SWE: Shallow -water exploratory well.
Synthetic-Based Drilling Fluid (SBF): A
drilling fluid that 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.
G-6
-------
Territorial Seas: The belt of the seas
measured from the line of ordinary low
water along that portion of the coast which
is in direct contact with the open sea and
the line marking the seaward limit of inland
waters, and extending seaward a distance of
3 miles.
THC: Total hydrocarbons.
TSP: Total suspended particulates.
TSS: Total Suspended Solids.
TWC: Treatment, workover, and completion.
UIC: Underground Injection Control.
Upland Site: A site not located in a wetland
area. May be an onshore site or a coastal
site under the Chapman Line definition.
U.S.C.: United States Code.
USCG: United States Coast Guard.
USDW: Underground Sources of Drinking
Water.
USGS: United States Geological Survey.
Vegetable Ester: A monoester of 2-
ethylhexanol and saturated fatty acids with
chain lengths in the range C8 - C16
Water-Based Drilling Fluid (WBF): A
drilling fluid in which water or a water
miscible fluid is the continuous phase and
the suspending medium for solids, whether
or not oil is present.
Workover: The performance of one or more
of a variety of remedial operations on a
producing oilwell to try to increase
production. Examples of workover j obs are
deepening, plugging back, pulling and re-
setting liners, and squeeze cementing.
G-7
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APPENDIX VII-1
CALCULATION OF
DISCHARGED CUTTINGS COMPOSITION
A-l
-------
Preceeding Page Blank
Deep, Development Model Well Data
Calculation of Discharged Cuttings Composition for Two Levels of Solids Control
11% (wt) Retention of SBF on Cuttings with 0.2% (vol) Crude Contamination
Total Waste in pounds (TW) = 0.11 TW+ [0.11 (0.2/0.47)] TW+ [0.11(0.33/0.47)] TW +(fraction that is DC) TW
= 0.11 TW + 0.0468TW + 0.0772TW + 0.76601 TW
lbs
bbls
TW =
DC/0.7660=
1,015,731
1,442
synthetic =
0.11 TW =
111,730
399
water =
0.0468 TW=
47,536
136
barite =
0.0772 TW =
78,414
52
cuttings =
model well size =
778,050
855
Adding 0.2% (vol) crude to whole mud discharged:
0.2% (vol) crude:
Total drilling fluid plus crude discharged =
Sum of synthetic plus crude =
bbls
lbs
587
237,681
1.2
345
588
238,026
400
112,076
7% (wt) Retention of SBF on Cuttings with 0.2% (vol) Crude Contamination
Total Waste in pounds (TW) = 0.07 TW + [0.07 (0.2/0.47)] TW + [0.07(0.33/0.47)] TW + (fraction that is DC) TW
= 0.07TW+ 0.0298TW + 0.0491TW + 0.8511 TW
lbs
bbls
TW =
DC/0.8511=
914,170
1,191
synthetic =
0.07 TW =
63,992
229
water =
0.0298 TW=
27,242
78
barite =
0.0491 TW =
44,886
30
cuttings =
model well size =
778,050
855
Adding 0.2% (vol) crude to whole mud discharged:
bbls lbs
Total drilling fluid discharged with cuttings = 336 136,120
0.2% (vol) crude: 0.7 198
Total drilling fluid plus crude discharged = 337 136,318
Sum of synthetic plus crude = 229 64,190
A-3
-------
Deep, Exploratory Model Well Data
Calculation of Discharged Cuttings Composition for Two Levels of Solids Control
11% (wt) Retention of SBF on Cuttings with 0.2% (vol) Crude Contamination
Total Waste in pounds (TW) = 0.11 TW+ [0.11 (0.2/0.47)] TW+ [0.11(0.33/0.47)] TW +(fraction that is DC) TW
= 0.11 TW + 0.0468TW + 0.0772TW + 0.7660 TW
lbs
bbls
TW =
DC/0.7660=
2,258,368
3,206
synthetic =
0.11 TW =
248,420
887
water =
0.0468 TW=
105,692
302
barite =
0.0772 TW =
174,346
116
cuttings =
model well size =
1,729,910
1,901
Adding 0.2% (vol) crude to whole mud discharged:
bbls lbs
Total drilling fluid discharged with cuttings = 1,305 528,458
0.2% (vol) crude: 2.6 767
Total drilling fluid plus crude discharged = 1,308 529,225
Sum of synthetic plus crude = 890 249,188
7% (wt) Retention of SBF on Cuttings with 0.2% (vol) Crude Contamination
Total Waste in pounds (TW) = 0.07 TW + [0.07 (0.2/0.47)] TW + [0.07(0.33/0.47)] TW + (fraction that is DC) TW
= 0.07TW+ 0.0298TW + 0.0491TW + 0.8511 TW
lbs
bbls
TW =
DC/0.8511=
2,032,558
2,648
synthetic =
0.07 TW =
142,279
508
water =
0.0298 TW=
60,570
173
barite =
0.0491 TW =
99,799
66
cuttings =
model well size =
1,729,910
1,901
Adding 0.2% (vol) crude to whole mud discharged:
bbls
lbs
Total drilling fluid discharged with cuttings =
747
302,648
0.2% (vol) crude:
1.5
440
Total drilling fluid plus crude discharged =
749
303,087
Sum of synthetic plus crude =
510
142,719
A-4
-------
Shallow, Development Model Well Data
Calculation of Discharged Cuttings Composition for Two Levels of Solids Control
11% (wt) Retention of SBF on Cuttings with 0.2% (vol) Crude Contamination
Total Waste in pounds (TW) = 0.11 TW+ [0.11 (0.2/0.47)] TW+ [0.11(0.33/0.47)] TW +(fraction that is DC) TW
= 0.11 TW + 0.0468TW + 0.0772TW + 0.7660 TW
lbs
bbls
TW =
DC/0.7660=
671,214
953
synthetic =
0.11 TW =
73,834
264
water =
0.0468 TW=
31,413
90
barite =
0.0772 TW =
51,818
34
cuttings =
model well size =
514,150
565
Adding 0.2% (vol) crude to whole mud discharged:
Total drilling fluid discharged with cuttings =
0.2% (vol) crude:
Total drilling fluid plus crude discharged =
Sum of synthetic plus crude =
bbls
388
0.£
389
264
lbs
157,064
228
157,292
74,062
7% (wt) Retention of SBF on Cuttings with 0.2% (vol) Crude Contamination
Total Waste in pounds (TW) = 0.07TW + [0.07 (0.2/0.47)] TW + [0.07(0.33/0.47)] TW + (fraction that is DC) TW
= 0.07TW+ 0.0298TW + 0.0491TW + 0.8511 TW
lbs
bbls
TW =
DC/0.8511=
604,101
787
synthetic =
0.07 TW =
42,287
151
water =
0.0298 TW=
18,002
51
barite =
0.0491 TW =
29,661
20
cuttings =
model well size =
514,150
565
Adding 0.2% (vol) crude to whole mud discharged:
Total drilling fluid discharged with cuttings =
0.2% (vol) crude:
Total drilling fluid plus crude discharged =
Sum of synthetic plus crude =
bbls
222
0.4
223
151
lbs
89,951
131
90,081
42,418
A-5
-------
Shallow, Exploratory Model Well Data
Calculation of Discharged Cuttings Composition for Two Levels of Solids Control
11% (wt) Retention of SBF on Cuttings with 0.2% (vol) Crude Contamination
Total Waste in pounds (TW) = 0.11 TW + [0.11 (0.2/0.47)] TW + [0.11(0.33/0.47)] TW + (fraction that is DC) TW
= 0.11 TW + 0.0468TW + 0.0772TW + 0.7660 TW
lbs
bbls
TW =
DC/0.7660=
1,406,580
1,997
synthetic =
0.11 TW =
154,724
553
water =
0.0468 TW=
65,828
188
barite =
0.0772 TW =
108,588
72
cuttings =
model well size =
1,077,440
1,184
Adding 0.2% (vol) crude to whole mud discharged:
Total drilling fluid discharged with cuttings =
0.2% (vol) crude:
Total drilling fluid plus crude discharged =
Sum of synthetic plus crude =
bbls
813
1.6
814
554
lbs
329,140
478
329,618
155,202
7% (wt) Retention of SBF on Cuttings with 0.2% (vol) Crude Contamination
Total Waste in pounds (TW) = 0.07 TW + [0.07 (0.2/0.47)] TW + [0.07(0.33/0.47)] TW + (fraction that is DC) TW
= 0.07TW+ 0.0298TW + 0.0491TW + 0.8511 TW
lbs
bbls
TW =
DC/0.8511=
1,265,938
1,650
synthetic =
0.07 TW =
88,616
316
water =
0.0298 TW=
37,725
108
barite =
0.0491 TW =
62,158
41
cuttings =
model well size =
1,077,440
1,184
Adding 0.2% (vol) crude to whole mud discharged:
bbls lbs
Total drilling fluid discharged with cuttings = 466 188,498
0.2% (vol) crude: 0.9 274
Total drilling fluid plus crude discharged = 466 188,772
Sum of synthetic plus crude = 317 88,889
A-6
-------
APPENDIX VIII-1
ZERO DISCHARGE:
HAULING AND ONSHORE WASTE DISPOSAL
CALCULATION OF SUPPLY BOAT FREQUENCY
A-7
-------
Preceeding Page Blank
SUPPLY BOAT FREQUENCY WORKSHEET
GULF OF MEXICO
Assumptions:
1. Cuttings box capacity = 25 bbl
2. Dedicated supply boat capacity = 80 boxes
3. Regularly scheduled supply boat arrives at rig every 4 days
4. Regularly scheduled supply boat capacity =12 boxes
5. Supply boat speed = 11.5 miles per hour
6. Platform/rig cuttings storage capacity =12 boxes
7. Total roundtrip distance for dedicated supply boat = 277 miles
Walk Haydel, 1989
Walk Haydel, 1989
Walk Haydel, 1989
Walk Haydel, 1989
Walk Haydel, 1989
Walk Haydel, 1989
Kennedy, 1998
Source:
(Port to rig =100 mi.; rig to disposal terminal = 117 mi.; terminal to port = 60 mi.)
8. Incremental mileage for regularly scheduled supply boat = 77 miles
Walk Haydel, 1989
(Total roundtrip - regular port to rig roundtrip = 277 - 200 = 77 mi.)
9. Supply boat maneuvering time at rig = lhr per trip
10. Additional boat idling at rig due to potential delays = 1.6 hrs per trip
11. Supply boat in-port unloading time and demurrage = 24 hrs per trip
12. Truck capacity =119 bbls
13. Roundtrip trucking distance from port to disposal facility = 20 miles
Jacobs Engineering, 1989
EPA, 1993
Walk Haydel, 1989
Walk Haydel, 1989
EPA, 1996
Deep Water Development Model Wells
Waste volume generated = 1,442 bbl
Table VII-4
Number of boxes of waste generated = 1442/25 = 58 boxes
Number of days to drill model well =5.4 days Pechan-Avanti, 1999
Number of supply boat trips = 1 dedictated trip
Number of days for supply boat:
(277 mi/11.5 mi per hr) + (1 hr maneuvering) + (1.6 hrs add. idling at rig) + (24 hrs per day*5.4 drilling days) + (24 hr demurrage) 180.29 hrs 7.51 days
Number of truck roundtrips = 1442/119 = 13 trips
Total truck miles = 13 * 20 = 260 mi.
Deep Water Exploratory Model Wells
Waste volume generated = 3,206 bbl Table VII-4
Number of boxes of waste generated = 3206/25 = 129 boxes
Number of days to drill model well = 12 days Pechan-Avanti, 1999
Number of supply boat trips = 2 dedictated trips; 1 regularly scheduled trip
Number of days for first dedicated supply boat:
(277 mi/11.5 mi per hr) + (1 hr maneuvering) + (1.6 hrs add. idling at rig) + (24 hrs per day*7 drilling days) + (24 hr demurrage) 218.7 hrs 9.11 days
Number of days for regularly scheduled supply boat:
(77 mi/11.5 mi perhr) + (1 hr maneuvering) + (1.6 hrs add. idling at rig) + (22 boxes/10 boxes per hr loading) + (24 hr demurrage) 35.50 hrs 1.48 days
Number of days for second dedicated supply boat:
(277 mi/11.5 mi per hr) + (1 hr maneuvering) + (1.6 hrs add. idling at rig) + (24 hrs per day* 4 drilling days) + (24 hr demurrage) 146.69 hrs 6.11 days
Supply boat days = 15.22 days for dedicated + 1.48 days for regularly scheduled = 16.70 days
Number of truck roundtrips = 3206/119 = 27 trips
Total truck miles = 27 * 20 = 540 mi.
A-9
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Shallow Water Development Model Wells
Waste volume generated = 953 bbl Table VII-4
Number of boxes of waste generated = 953/25 = 39 boxes
Number of days to drill model well =3.6 days Pechan-Avanti, 1999
Number of supply boat trips = 1 dedictated trip
Number of days for supply boat:
(277 mi/11.5 mi per hr) + (1 hr maneuvering) + (1.6 hrs add. idling at rig) + (24 hrs per day*3.6 drilling days) + (24 hr demurrage) 137.09 hrs 5.71 days
Number of truck roundtrips = 953/119 = 8 trips
Total truck miles = 8 * 20 = 160 mi.
Shallow Water Exploratory Model Wells
Waste volume generated = 1,997 bbl
Number of boxes of waste generated = 1997/25 = 80 boxes
Number of days to drill model well = 7.5 days
Number of supply boat trips = 1 dedictated trip
Number of days for supply boat:
(277 mi/11.5 mi per hr) + (1 hr maneuvering) + (1.6 hrs add. idling at rig) + (24 hrs per day*7.5 drilling days) + (24 hr demurrage) 230.69 hrs 9.61 days
Number of truck roundtrips = 1997/119 = 17 trips
Total truck miles = 17 * 20 = 340 mi.
Table VII-4
Pechan-Avanti, 1999
OFFSHORE CALIFORNIA
Assumptions:
1. Cuttings box capacity = 25 bbl
2. Dedicated supply boat capacity = 80 boxes
3. Supply boat speed = 11.5 miles per hour
4. Platform/rig cuttings storage capacity = 12 boxes
5. Total roundtrip distance for dedicated supply boat = 200 miles
(Port to rig =100 mi)
6. Supply boat maneuvering time at rig = lhr per trip
7. Additional boat idling at rig due to potential delays = 1.6 hrs per trip
8. Supply boat in-port unloading time and demurrage = 24 hrs per trip
9. Truck capacity = 50 bbls
10. Roundtrip trucking distance from port to disposal facility = 300 miles
Source:
Walk Haydel, 1989
Kennedy, 1998
Walk Haydel, 1989
Walk Haydel, 1989
Walk Haydel, 1989
Jacobs Engineering, 1989
EPA, 1993
Walk Haydel, 1989
Walk Haydel, 1989
Mileage from Bakersfield to Ventura, California
Deep Water Development Model Wells
Waste volume generated = 1,442 bbl
Number of boxes of waste generated = 1442/25 = 58 boxes
Number of days to drill model well = 5.4 days
Number of supply boat trips = 1 dedictated trip
Table VII-4
Pechan-Avanti, 1999
Number of days for supply boat:
(200 mi/11.5 mi per hr) + (1 hr maneuvering) + (1.6 hrs add. idling at rig) + (24 hrs per day*5.4 drilling days) + (24 hr demurrage) 173.59 hrs 7.23 days
Number of truck roundtrips = 1442/50 = 29 trips
Total truck miles = 29 * 300 = 8700 mi.
A-10
-------
Shallow Water Development Model Wells
Waste volume generated = 953 bbl Table VII-4
Number of boxes of waste generated = 953/25 = 39 boxes
Number of days to drill model well =3.6 days Pechan-Avanti, 1999
Number of supply boat trips = 1 dedictated trip
Number of days for supply boat:
(200 mi/11.5 mi per hr) + (1 hr maneuvering) + (1.6 hrs add. idling at rig) + (24 hrs per day*3.6 drilling days) + (24 hr demurrage) 130.39 hrs 5.43 days
Number of truck roundtrips = 953/50 = 20 trips
Total truck miles = 20 * 300 = 6000 mi.
COOK INLET, ALASKA
Assumptions:
1. Cuttings box capacity = 8 bbl
2. Dedicated supply boat capacity =132 boxes
3. Supply boat speed = 11.5 miles per hour
4. Platform/rig cuttings storage capacity = 12 boxes
5. Total roundtrip distance for dedicated supply boat = 50 miles
(Port to rig = 25 mi)
6. Supply boat maneuvering time at rig = lhr per trip
7. Additional boat idling at rig due to potential delays = 1.6 hrs per trip
8. Supply boat in-port unloading time and demurrage = 24 hrs per trip
9. Truck capacity = 64 bbls
10. Trucking distance from port to disposal facility in Oregon = 2,200 miles
Shallow Water Development Model Wells
Waste volume generated = 953 bbl
Number of boxes of waste generated = 953/25 = 39 boxes
Number of days to drill model well = 3.6 days
Number of supply boat trips = 1 dedictated trip
Number of days for supply boat:
(50 mi/11.5 mi per hr) + (1 hr maneuvering) + (1.6 hrs add. idling at rig) + (24 hrs per day*3.6 drilling days) + (24 hr demurrage) = 117.35 hrs = 4.89 days
Number of truck trips = 953/64 = 15 trips
Total truck miles = 15 * 2200 = 11,000 mi.
Sources:
Walk Haydel: Carriere, J. and E. Lee, Walk, Haydel and Associates, Inc., "Water-Based Drilling Fluids and Cuttings Disposal Study Update," Offshore
Effluent Guidelines Comments Research Fund Administered by Liskow and Lewis, January 1989.
Kennedy, 1998: Kennedy, Kerri, The Pechan-Avanti Group, Telecommunications Report on conversation with John Belsome, Seabulk Offshore Ltd.,
regarding "Offshore supply boat costs and specifications," June 3, 1998.
Jacobs Engineering: Jacobs Engineering Group, "Air Quality Impact of Proposed Lease Sale No. 95," prepared for U.S. Department of the Interior, Minerals
Management Service, June 1989.
EPA, 1993: U.S. Environmental Protection Agency, Development Document for Effluent Limitations Guidelines and New Source Performance
Standards for the Offshore Subcategory of the Oil and Gas Extraction Point Source Category, Final, EPA 821-R-93-003, January 1993.
EPA, 1996: U.S. Environmental Protection Agency, Development Document for Final Effluent Limitations Guidelines and Standards for the Coastal
Subcategory of the Oil and Gas Extraction Point Source Category, EPA 821-R-96-023, October 1996.
Pechan-Avanti: The Pechan-Avanti Group, Worksheet regarding "Number of Days to Drill Model SBF Wells," October 27, 1998.
Source:
EPA, 1996
EPA, 1996
Walk Haydel, 1989
Walk Haydel, 1989
EPA, 1996
Jacobs Engineering, 1989
EPA, 1993
Walk Haydel, 1989
EPA, 1996
EPA, 1996
Table VII-4
Pechan-Avatni, 1999
A-ll
-------
Preceeding Page Blank
APPENDIX VIII-2
BAT COMPLIANCE COST CALCULATIONS
A-13
-------
Preceeding Page Blank
Summary BAT Costs for Management of SBF Cuttings (1997$)
"20% OBF Wells Convert" Scenario
Baseline Costs: Total Annual
Baseline Technology
GOM
CA-Offshore
AK-Cook
Total
Per Techn.
NOTES
Discharge with 11% retention of base fluid
19,113,650
0
0
19,113,650
From Worksheet No. 1
on cuttings (94 SBF wells in GOM)
Zero Dischargecurrent OBF users only
2,821,816
2,157,023
207,733
5,186,572
From Worksheet No.s 1, 2, and 3
(23 GOM wells; 12 CA wells; 1 AK well)
TOTAL Per Region
21,935,466
2,157,023
207,733
24,300,222
Compliance Costs: Total Annual
Option
GOM
CA-Offshore
AK-Cook
Total
NOTES
Discharge with 7% retention of base fluid on cuttings*
15,950,550
1,647,883
115,467
17,713,900
From Worksheet No.s 4, 5, and 6
Zero Discharge
(94 current SBF wells)
26,077,546
NA
NA
26,077,546
From Worksheet No.s 7, 8, and 9
*For GOM: 94 current SBF wells + 23 current OBF wells
For CA: 12 wells
For Cook Inlet, AK: 1 well
Incremental Compliance Costs: Total Annual
Option
GOM
CA-Offshore
AK-Cook
Total
NOTES
Discharge with 7% retention of base fluid on cuttings
(5,984,916)
(509,140)
(92,265)
(6,586,322)
Diff btwn compliance and total
baseline cost
Zero Discharge**
6,963,896
0
0
6,963,896
Diff. btwn compliance cost and
discharge baseline cost
"Compares zero-discharge compliance costs to baseline discharge costs for 94 wells currently using SBF and discharging SBF-coated cuttings.
A-15
-------
Worksheet No. 1
Compliance Cost Estimates: Baseline Current Practice
Region:
Technologies:
Model Well Types:
Per-Well Waste Volumes:
Offshore Gulf of Mexico
Discharge of SBF-cuttings via primary and secondary shale shakers w/ average retention of 11% (wt) base fluid on cuttings
Zero discharge of OBF cuttings via haul & land-dispose (80%) plus on-site grinding and injection (20%)
All four types: Deep- and Shallow-water, Development and Exploratory
Deep-water Development:
1,442
bbls
587
bbls
Deep-water Exploratory:
3,206
bbls
1,305
bbls
Shallow-water Development:
953
bbls
00
OO
CO
bbls
Shallow-water Exploratory:
1,997
bbls
813
bbls
Cost Item
Deep-Water Using SBF
Shallow-Water Using SBF
Shallow-Water Using OBF
TOTAL
Notes
Development
Exploratory
Developmen
Exploratory
Development
Exploratory
Drilling Fluid Costs for Wells Currently Using SBF
(SBF@ $200/bbl lost w/ cuttings)
117,400
261,000
77,600
162,600
Section VIII.3.1.3.2
SPP Toxicity Monitoring Test
575
575
575
575
Section VIII.3.1.3.1
Per-Well Cost to Haul and Dispose (S/well)
Per-Well Cost to Grind and Inject (S/well)
97,288
67,620
191,490
141,225
From Worksheet No. 7 (GOM Haul & Dispose);
includes cost of drilling fluid lost w/ cuttings
From Worksheet No. 8 (GOM Injection);
includes cost of drilling fluid lost w/ cuttings
Per Well Baseline Cost (S/well)
Unit Cost (S/bbl)
117,975
82
261,575
82
78,175
82
163,175
82
91,355
96
181,437
91
Assumes for wells currently using OBF:
80% hauls and 20% injects
No. Wells
TOTAL ANNUAL BASELINE GOM COST (S)
18
2,123,550
57
14,909,775
12
938,100
7
114,222
15
1,370,318
8
1,451,498
21,935,466
For wells currently using OBF, 20% (23 of 112
will convert from OBF to SBF
Per-well costs x no. of wells
Subtotal for SBF Wells: 19,113,650
Subtotal for OBF Wells: 2,821,816
A-16
-------
Worksheet No. 2
Compliance Cost Estimates: Baseline Current Practice
Region: Offshore California
Technology: Zero-Discharge via Haul and Land-Dispose
Model Well Types: Deep- and Shallow-water Development Wells
Per-Well Waste Volumes:
Deep-water Devel.: 1,442bbls waste OBF-cuttings (generated with 11% retention, 0.2% crude contamination)
587bbls OBF lost with cuttings
Shallow-water Devel: 953 bbls waste OBF-cuttings (generated with 11% retention, 0.2% crude contamination)
3 88 bbls OBF lost with cuttings
Cost Item
Deep-Water
Devel. Well
Shallow-Water
Devel. Well
TOTAL
Notes
Disposal Cost ($12.32/bbl)
17,765
11,741
Vendor quote of $35/ton x 704 lbs cuttings/bbl (Section VIII.3.1.4.1)
Handling Cost ($7.52/bbl)
8,350
5,518
Handling costs = 47% of disposal costs (proportion from
GOM costs)
Container Rental
($40/box/day * "x" boxes* "y" days to fill & haul)
16,704
8,424
GOM vendor quote times geographic area multiplier:
($25/box/day x 1.6) (Section VIII.3.1.4.1)
Supply Boat Cost ($8,500/day)
61,200
45,900
Vendors (Section VIII.3.1.4.1)
Trucking Cost ($354/truck load)
10,266
6,903
Truck rate ($65/hr x 300 mi r.t. @55mph) x
"x" boxes @ 2 boxes per truck (Section VIII.3.1.4.1)
Drilling Fluid Costs
COBF lost with cuttings (a) tiHO/bbh
70,440
46,560
GOM vendor quote times geographic area
multiplier
-------
Worksheet No. 3
Compliance Cost Estimates: Baseline Current Practice
Region: Cook Inlet, Alaska
Technology: Zero-Discharge via Haul and Land-Dispose
Model Well Types: Shallow-Water Development Wells
Per-Well Waste Volumes:
Shallow-water Devel: 953 bbls waste OBF-cuttings (generated with 11% retention, 0.2% crude contamination)
388 bbls OBF lost with cuttings
Cost Item
Shallow-Water
Development Well
Notes
Disposal Cost ($533 per 8-bbl box)
63,494
Vendor quote of $500/box in 1995; ENR
CCI ratio of 1997$/1995$ = 1.065 (Section VIII.3.1.4.1)
8-bbl Cuttings Box Purchase Cost ($133/box)
15,844
Operator quotes of $125/box in 1995; ENR
CCI ratio of 1997$/1995$ = 1.065 (Section VIII.3.1.4.1)
Supply Boat Cost ($8,500/day)
41,650
Vendors (Section VIII.3.1.4.1)
Trucking Cost ($1,917 per 8-box truckload)
28,545
Vendor quote of $1,800 per 22-ton truckload in 1995,
ENR CCI ratio of 1997$/1995$ = 1.065 (Section VIII.3.1.4.1)
Drilling Fluid Cost
(OBF lost with cuttings 'a $150/bbl)
58,200
Vendor quote times geographic area
multiplier of 2 for Cook Inlet (Section VIII.3.1.4.1)
TOTAL Cost per Model Well ($)
207,733
Unit Cost ($/bbl)
218
No. Wells
1
TOTAL ANNUAL BASELINE Cook Inlet COST($)
207,733
Per-well costs x 1 shallow-water development wells
A-18
-------
Worksheet No. 4
Compliance Cost Estimates: Discharge with Improved Solids Control
Region:
Technology:
Model Well Types:
Per-Well Waste Volumes:
Deep-water Development:
Deep-water Exploratory:
Shallow-water Development:
Shallow-water Exploratory:
Offshore Gulf of Mexico
Discharge via add-on drill cuttings "dryer" with average retention of 7% (wt) base fluid on cuttings
All four types: Deep- and Shallow-water, Development and Exploratory
1,191 bbls waste SBF-cuttings (generated with 7% retention, 0.2% crude contamination)
336 bbls SBF lost with cuttings
2,648 bbls waste SBF-cuttings (generated with 7% retention, 0.2% crude contamination)
747 bbls SBF lost with cuttings
787 bbls waste SBF-cuttings (generated with 7% retention, 0.2% crude contamination)
222 bbls SBF lost with cuttings
1,650 bbls waste SBF-cuttings (generated with 7% retention, 0.2% crude contamination)
466 bbls SBF lost with cuttings
Cost Item
Deep Water
Devel. Well
Deep Water
Exnlor. Well
Shallow Water
Devel. Well
Shallow Water
Exnlor. Well
TOTAL
Notes
GOM Wells C .urrentlv lisine Sltl- mill Dischiirsjiii!; ( uttinsjs
Add-on Solids Control Equipment @ $1200/day
(Cuttings dryer that reduces base fluid retention
from 11% to 7%; drilling days = 40% of time on rig)
Retrofit Additional Deck Space @ $340/sq ft
(Add 75 sq ft for equipment plus tank per rig)
Drilling Fluid Costs
(SBF lost with cuttings @ $200/bbl)
Monitoring Analyses
Crude Contamination of Drilling Fluid @ $50/test
Retention of Base Fluids by Retort @ $50/test
16,200
3,923
67,200
50
1,300
36,000
3,923
149,400
50
1,700
10,800
3,923
44,400
50
1,500
22,500
3,923
93,200
50
2,000
Includes all equipment, labor, and materials
(e.g., retort analysis); days of
rental from industry (Section VIII.3.1.3.2)
Costs and wells-per-rig from offshore model;
space required from Amoco trip report
(Section VIII.3.1.3.2)
Cost from Amoco trip report, and additional
industry sources (Section VIII.3.1.3.2)
Cost from vendor (Section VIII.3.1.3.2)
Retort measured twice per 500 ft drilled;
cost from vendor ("Section VIII.3.1.3.2s)
TOTAL Cost Per Well (S)
Unit Cost (S/bbl)
No. Wells
TOTAL ANNUAL GOM Cost for SBF Wells (S)
88,673
74
18
1.596.115
191,073
72
57
10.891.165
60,673
77
12
"28.0
121,673
74
7
851.-12
I4.06".069
Per-well cosls \ no. of wells
(iOM W ills C 'urrentlv I sin
-------
Worksheet No. 5
Compliance Cost Estimates: Discharge with Improved Solids Control
Region:
Technology:
Model Well Types:
Per-Well Waste Volumes
336 bbls SBF lost with cuttings
Shallow-water Development: 787 bbls waste SBF-cuttings (generated with 7% retention, 0.2% crude contamination)
222 bbls SBF lost with cuttings
Offshore California
Discharge via add-on drill cuttings "dryer" with average retention of 7% (wt) base fluid on cuttings
Deep- and Shallow-Water Development Wells
Deep-water Development: 1,191 bbls waste SBF-cuttings (generated with 7% retention, 0.2% crude contamination)
Cost Item
Deep-Water
Development
Shallow-Water
Development
TOTAL
Notes
Add-on Solids Control Equipment @ $1920/day
(Cuttings dryer that reduces base fluid retention
from 11% to 7%; drilling days = 40% of time on rig)
25,920
17,280
Includes all equipment, labor, and materials (e.g., retort
analysis); Geographic Area Cost Multiplier of 1.6
from Offshore DD; rental days from industry
(Section VIII. 3.1.3.2)
Retrofit Additional Deck Space @ $544/sq ft
(Add 75 sq ft for equipment plus tank per rig)
6,277
6,277
Costs and wells-per-rig from offshore model;
space required from Amoco trip report (Section VIII.3.1.3.2)
Drilling Fluid Costs
(SBF lost with cuttings @ $320/bbl)
107,520
71,040
Cost from Amoco trip report, and additional industry sources;
Geographic Area Cost Multiplier of 1.6 from Offshore DD
(Section VIII. 3.1.3.2)
Monitoring Analyses
Crude Contamination of Drilling Fluid @ $50/test
Retention of Base Fluids by Retort @ $50/test
50
1,300
50
1,500
Cost from vendor (Section VIII.3.1.3.2)
Retort measured twice per 500 ft drilled;
cost from vendor (Section VIII.3.1.3.2)
TOTAL Cost Per Well ($)
141,067
96,147
Unit Cost ($/bbl)
118
122
No. Wells
11
1
TOTAL ANNUAL CA Cost ($)
1,551,736
96,147
1,647,883
Per-well costs x no. of wells
A-20
-------
Worksheet No. 6
Compliance Cost Estimates: Discharge with Improved Solids Control
Region: Cook Inlet, Alaska
Technology: Discharge via add-on drill cuttings "dryer" with average retention of 7% (wt) base fluid on cuttings
Model Well Types: Shallow-Water Development Wells
Per-Well Waste Volumes:
Shallow-water Development: 787 bbls waste SBF-cuttings (generated with 7% retention, 0.2% crude contamination)
222 bbls SBF lost with cuttings
Cost Item
Shallow-Water
Development
Notes
Add-on Solids Control Equipment @ $2400/day
(Cuttings dryer that reduces base fluid retention
from 11% to 7%; drilling days = 40% of time on rig)
21,600
Includes all equipment, labor, and materials (e.g., retort analysis);
Geographic Area Cost Multiplier of 2 from Offshore DD
(Section VIII. 3.1.3.2)
Retrofit Additional Deck Space @ $680/sq ft
(Add 75 sq ft for equipment plus tank per rig;
applied to all platforms)
3,517
Costs from offshore model; wells-per-rig from Coastal DD;
space required from Amoco trip report (Section VIII.3.1.3.2)
Drilling Fluid Costs
(SBF lost with cuttings @ $400/bbl)
88,800
Cost from Amoco trip report, and additional industry sources;
Geographic Area Cost Multiplier of 2 from Offshore DD
(Section VIII. 3.1.3.2)
Monitoring Analyses
Crude Contamination of Drilling Fluid @ $50/test
Retention of Base Fluids by Retort @ $50/test
50
1,500
Cost from vendor (Section VIII.3.1.3.2)
Retort measured twice per 500 ft drilled; cost from vendor
(Section VIII. 3.1.3.2)
TOTAL Cost Per Well ($)
115,467
Unit Cost ($/bbl)
147
No. Wells
1
TOTAL ANNUAL Cook Inlet Cost ($)
115,467
Per-well costs x 1 shallow-water development well
A-21
-------
Worksheet No. 7
Compliance Cost Estimates: Zero Discharge GOM
Offshore Gulf of Mexico
Zero-Discharge via Haul and Land-Dispose
All four types: Deep- and Shallow-water, Development and Exploaratory
Deep-water Development: 1,442 bbls waste SBF/OBF-cuttings (generated with 11% retention, 0.2% crude contamination)
587 bbls SBF/OBF lost with cuttings
Deep-water Exploratory: 3,206 bbls waste SBF/OBF-cuttings (generated with 11% retention, 0.2% crude contamination)
1,305 bbls SBF/OBF lost with cuttings
Shallow-water Development: 953 bbls waste SBF/OBF-cuttings (generated with 11% retention, 0.2% crude contamination)
388 bbls SBF/OBF lost with cuttings
Shallow-water Exploratory: 1,997 bbls waste SBF/OBF-cuttings (generated with 11% retention, 0.2% crude contamination)
813 bbls SBF/OBF lost with cuttings
Cost Item
Deep-Water
Deep-Water
Lxolor. Well
Shallow Water
Devel. Well
Shallow Water
Fxplor. Well
Notes
Disposal Cost (S10.13 bbl)
9,654
20,230
Average of $9.50 and $10.75, quoted
from vendors (Section VM.3.1.4.1)
Handling Cost ($4.75/bbl)
-
-
4,527
9,486
Vendor quote; includes crains, labor,
trucks to landfill, etc. (Section VIII.3.1.4.1)
Container Rental
($25/box/day * "x" boxes* "y" days to fill & haul)
-
-
5,558
19,200
Vendor (S ection VIII. 3.1.4.1)
Supply Boat Cost ($8,500/day)
-
-
48,450
81,600
Vendors (Section VIII.3.1.4.1)
Drilling Fluid Costs
COBFlost with cuttings la) $75/bbl1
-
-
29,100
60,975
Vendor quote (Section VIII.3.1.4.1)
TOTAL Cost per Model Well ($)
-
-
97,288
191,490
Unit Cost to TTnul and Dispose tS hhli
in:
96
Disposal Cost ($10.13/bbl)
14,607
32,477
...
...
Average of $9.50 and $10.75, quoted
from vendors (Section VIIL3.1.4.1)
Handling Cost ($4.75/bbl)
6,850
15,228
-
-
Vendor quote; includes crains, labor, trucks
to landfill, etc. (Section VIII.3.1.4.1)
Container Rental
($25/box/day * "x" boxes* "y" days to fill & haul)
10,875
53,858
-
-
Vendor (S ection VIII. 3.1.4.1)
Supply Boat Cost ($8,500/day)
63,750
141,950
-
-
Vendors (Section VIII.3.1.4.1)
Drilling Fluid Costs
CSBFlost with cuttings la) $700/bbl1
117,400
97,875
-
-
Vendor and operator quotes
(¦Section VTTT.3.1.3.2't
TOTAL Cost per Model Well ($)
213,482
341,388
-
-
Unit Cost to Haul and Dispose ($/bbl)
148
106
Region:
Technology:
Model Well Types:
Per-Well Waste Volumes:
A-22
-------
Worksheet No. 8
Compliance Cost Estimates: Zero Discharge GOM
Region:
Technology:
Model Well Types:
Per-Well Waste Volumes:
Deep-water Development:
Deep-water Exploratory:
Shallow-water Development:
Shallow-water Exploratory:
Offshore Gulf of Mexico
Zero-Discharge via On-site Grinding and Injection
All four types: Deep- and Shallow-water, Development and Exploaratory
1,442 bbls waste OBF-cuttings (generated with 11% retention, 0.2% crude contamination)
587 bbls OBF lost with cuttings
3,206 bbls waste OBF-cuttings (generated with 11% retention, 0.2% crude contamination)
1,305 bbls OBF lost with cuttings
953 bbls waste OBF-cuttings (generated with 11% retention, 0.2% crude contamination)
388 bbls OBF lost with cuttings
1,997 bbls waste OBF-cuttings (generated with 11% retention, 0.2% crude contamination)
813 bbls OBF lost with cuttings
Cost Item
COM Wells I sinii SI5I-" Assumed lo S«
Deep-Water
Shallow-Water
Notes
Development | Exploratory
ilcli lo OIJI-" I nder Zero Discharge
Development | Explorntoiy
Onsite Injection System @ $4280/day
(drilling days = 40% of time on rig)
Drilling Fluid Costs
(OBF lost with cuttings (a), $75/bbl)
38,520
29,100
80,250
60,975
Includes all equipment, labor, and services; vacuum
system used to transport cuttings (Section
TOTAL Cost per Model Well ($)
Unit Cost to Grind and Inject ($/bbl)
;;
;;
67,620
71
141,225
71
COM Wells I sin" Mil-' Assumed lo Retain SI}I' I nder Zero Discharge
Onsite Injection System @ $4280/day
(drilling days = 40% of time on rig)
Drilling Fluid Costs
(OBF lost with cuttings (a),
57,780
117,400
128,400
261,000
Includes all equipment, labor, and services; vacuum
system used to transport cuttings (Section
TOTAL Cost per Model Well ($)
Unit Cost to Grind and Inject ($/bb!)
175,180
121
389,400
121
A-23
-------
Preceeding Page Blank
Worksheet No. 9
Compliance Cost Estimates: Zero Discharge GOM
Region:
Technology:
Model Well Types:
Per-Well Waste Volumes:
Offshore Gulf of Mexico
Zero-Discharge via Haul & Land-Dispose (80%) plus On-site Grinding and Injection (20%)
All four types: Deep- and Shallow-water, Development and Exploaratory
Deep-water Development:
1,442
587
Deep-water Exploratory:
3,206
1,305
Shallow-water Development:
953
388
Shallow-water Exploratory:
1,997
813
Cost Item
Deep-Water
Shallow-Water
TOTAL
Notes
Development
Exploratory
Development
Exploratory
COM Wells I siii» SI5I-" Assumed lo Switch lo OBI-' I nder Zero Disihanu-
l Jnit Cost to Haul and Dispose ($/well)
97,288
191,490
From Worksheet No. 7
Unit Cost to Grind and Iniect fS/welF)
67,620
141,225
From Worksheet No. 8
Weighted Average Per Well Cost ($/well)
91,355
181,437
Assumes 80%) hauls and 20% injects
Weighted Average Unit Cost ($/bbl)
96
91
No. Wells
12
7
SUBTOTAL A\M AT. GOM ZD C OST (Si
1.096.254
1.270.061
2.366,315
Per-well costs \ no. of wells
COM Wells I siii» SI5I-" Assumed lo kelaiu SBI-" I nder Zero Disihanje
Unit Cost to Haul and Dispose ($/well)
213,482
341,388
From Worksheet No. 7
Unit Cost to Grind and Iniect fS/welF)
175,180
389,400
From Worksheet No. 8
Weighted Average Per Well Cost ($/well)
205,822
350,990
Assumes 80% hauls and 20% injects
Weighted Average Unit Cost ($/bbl)
143
109
No. Wells
18
57
SUBTOTAL ANNUAL GOM ZD COST (S)
3,704,788
20,006,443
23.711.231
Per-well costs x no. of wells
Total Annual GOM Costs for Zero Discharge (S)
26.077.546
A-24
-------
APPENDIX VIII-3
NSPS COMPLIANCE COST CALCULATIONS
A-25
-------
Preceeding Page Blank
Summary NSPS Costs for Management of SBF Cuttings (1997$)
Baseline Costs: Total Annual
Baseline Technology
GOM
NOTES
Discharge with 11% retention of base fluid
on cuttings
2,201,725
From Worksheet No. 1; applies to
19 SBF wells
NSPS Compliance Costs: Total Annual
Option
GOM
NOTES
Discharge
0
From Worksheet No. 2; applies to
19 SBF wells
Zero Discharge
3,796,143
From Worksheet No. 5; applies to
19 SBF wells
Incremental NSPS Compliance Costs: Total Annual
Option
GOM
NOTES
Discharge
(2,201,725)
Diff. between compliance and
baseline costs
Zero Discharge
1,594,418
Diff. between compliance and
baseline costs
A-27
-------
Worksheet No. 1
NSPS Compliance Cost Estimates: Baseline Current Practice
Region: Offshore Gulf of Mexico
Technology: Discharge of SBF cuttings via add-on cuttings "dryer" w/ avg. ret.'n of 11% (wt) base fluid on cuttings
Model Well Types: Deep- and Shallow-water Development
Per-Well Waste Volumes:
Deep-water Development: 1,442 bbls waste SBF-cuttings (generated with 11% retention, 0.2% crude contamination)
587 bbls SBF lost with cuttings
Shallow-water Development: 953 bbls waste SBF-cuttings (generated with 11% retention, 0.2% crude contamination)
388 bbls SBF lost with cuttings
Cost Item
Deep-Water
Development
Shallow-Water
Development
TOTAL
Notes
Drilling Fluid Costs for Wells Currently Using SBF
(SBF@ $200/bbl lost w/ cuttings)
117,400
77,600
Costs from Amoco trip report and additional industry
sources (Section VIII.3.1.3.2)
SPP Toxicity Monitoring Test
575
575
Average cost for full analysis (Section VIII.3.1.3.1)
Per Well Baseline Cost ($/well)
117,975
78,175
Unit Cost ($/bbl)
82
82
No. Wells
18
1
TOTAL ANNUAL BASELINE GOM COST ($)
2,123,550
78,175
2,201,725
Per-well costs x no. of wells
A-28
-------
Worksheet No. 2
NSPS Compliance Cost Estimates: Discharge with Improved Solids Control
Region:
Technology:
Model Well Types:
Per-Well Waste Volumes
336 bbls SBF lost with cuttings
Shallow-water Development: 787 bbls waste SBF-cuttings (generated with 7% retention, 0.2% crude
222 bbls SBF lost with cuttings
Offshore Gulf of Mexico
Discharge via add-on drill cuttings "dryer" with average achievable retention of 7% (wt) base fluid
Deep- and Shallow-water Development
Deep-water Development: 1,191 bbls waste SBF-cuttings (generated with 7% retention, 0.2% crude
Cost Item
Deep-Water
Dc\ elopmenl Well
Shallow-Water
Dc\ olopnionl Well
TOTAL
Notes
GOiYl Wells (uiiviKlv I sini± SB I- ;nul Dischii r<±iii<±
Improved Solids Coiiuol Lquipiiiciii
(Cuttings dryer that reduces base fluid retention
from 11% to 7%; drilling days = 40% of time on rig)
16,200
10,800
Includes all equipment, labor, and materials
(e.g., retort analysis); days of rental from
industry (Section VIII.3.1.3.2)
Drilling Fluid Costs
(SBF lost with cuttings @ $200/bbl)
67,200
44,400
Cost from Amoco trip report, and additional
industry sources (Section VIII.3.1.3.2)
Monitoring Analyses
Crude Contamination of Drilling Fluid @ $50/test
Retention of Base Fluids by Retort @ $50/test
50
1,300
50
1,500
Cost from vendor (Section VIII.3.1.3.2)
Retort measured twice per 500 ft drilled cost
from vendor (Section VIII.3.1.3.2)
TOTAL Cost Per Well ($)
84,750
56,750
Unit Cost ($/bbl)
71
72
No. Wells
18
1
TOTAL ANNUAL GOM Cost for SBF Wells CS)
1.525.500
56.750
1.582.250
Per-well costs x no. of wells
A-29
-------
Worksheet No. 3
NSPS Compliance Cost Estimates: Zero Discharge GOM
Region:
Technology:
Model Well Types:
Per-Well Waste Volumes:
Offshore Gulf of Mexico
Zero-Discharge via Haul and Land-Dispose
Deep- and Shallow-water Development
Deep-water Development:
Shallow-water Development:
1,442 bbls waste SBF/OBF-cuttings (generated with 11% retention, 0.2% crude contam.)
587 bbls SBF/OBF lost with cuttings
953 bbls waste SBF/OBF-cuttings (generated with 11% retention, 0.2% crude contam.)
388 bbls SBF/OBF lost with cuttings
Cost Item
Deep-Water
Development Well
Shallow-Water
Development Well
Notes
COM NilM -.ill-' Mil A-Mimed In Suilili In OI5I- 1 n
Irr /cni l)iM'li;i r"('
Disposal Cost ($10.1.? bbl)
9,654
Average of $9.50 and $10.75, quoted from vendors (Section VIII.3.1.4.1)
Flandling Cost ($4.75/bbl)
4,527
Vendor quote; includes crains, labor, trucks to landfill, etc. (Section VIII.3.1.4.1)
Container Rental
($25/box/day * "x" boxes* "y" days to fill & haul)
5,558
Vendor (Section VIII.3.1.4.1)
Supply Boat Cost ($8,500/day)
48,450
Vendors (Section VIII.3.1.4.1)
Drilling Fluid Costs
COBF lost with cuttines (a) $75/bbH
29,100
Vendor quote (Section VIII.3.1.4.1)
TOTAL Cost per Model Well (S)
97,288
Unit Cost to Haul and Dispose f$/lilil I
102
(i()M Well- 1 »iii« SI5I- V-Mimcd lo kclaiii Mil- 1 lltlil
/.riii l>Ki'h:ir
-------
Worksheet No. 4
NSPS Compliance Cost Estimates: Zero Discharge GOM
Region: Offshore Gulf of Mexico
Technology: Zero-Discharge via On-site Grinding and Injection
Model Well Types: Deep- and Shallow-water Development
Per-Well Waste Volumes:
Deep-water Development: 1,442 bbls waste SBF/OBF-cuttings (generated with 11% retention, 0.2% crude contam.)
587 bbls OBF lost with cuttings
Shallow-water Development: 953 bbls waste SBF/OBF-cuttings (generated with 11% retention, 0.2% crude contam.)
388 bbls OBF lost with cuttings
Cost Item
Deep-Water
Development Well
Shallow-Water
Development Well
Notes
GO.M Wells I sinii Mil-' Assumed lo Switch lo OBI' I nder /.cm Discharge
Onsite Injection System @ $4280/day
(drilling days = 40% of time on rig)
Drilling Fluid Costs
(OBF lost with cuttings <7 $75/bbl)
38,520
29,100
Includes all equipment, labor, and services; vacuum
system used to transport cuttings (Section VIII. 3.1.5)
Cost from vendor (Section VIII.3.1.4.1)
TOTAL Cost per Model Well ($)
Unit Cost to Grind and In ject ($/bbl)
67,620
71
(>()M Wells I si ii ii SI5I-" Assumed In Retain SB I' I ndcr Zero Discharge
Onsite Injection S\ stem
-------
Worksheet No. 5
NSPS Compliance Cost Estimates: Zero Discharge GOM
Region:
Technology:
Model Well Types:
Per-Well Waste Volumes:
Deep-water Development:
Shallow-water Development:
Offshore Gulf of Mexico
Zero-Discharge via Haul & Land-Dispose (80%) plus On-site Grinding and Injection (20%)
Deep- and Shallow-water Development
1,442 bbls waste SBF/OBF-cuttings (generated with 11% retention, 0.2% crude contamination)
587 bbls SBF/OBF lost with cuttings
953 bbls waste SBF/OBF-cuttings (generated with 11% retention, 0.2% crude contamination)
388 bbls SBF/OBF lost with cuttings
Cost Item
Deep-Water
Shallow-Water
TOTAL
Notes
Dcvcloomenl
Development
GOM Wells I sill" SB I' Assumed In Switch lo OIJI-" I mler /.ei
¦o Discharge
L ml Cosl io 1 l.nil and Dispose (S well;
:xx
1'roni Worksheet No. 3
Unit Cost to Grind and Iniect ($/well)
0
From Worksheet No. 4
Weighted Average Per Well Cost ($/well)
91,355
Assumes 80% hauls and 20% injects
Weighted Average Unit Cost ($/bbl)
96
No. Wells
1
SUBTOTAL AWT AT. GOAT ZD COST (S)
9 l."o 5
01.355
Pei'-uell cosis \ no of wells
GOM Wells I sin*! SB I' Assumed lo Kclain SBI
" I mler Zero Discharge
Unit Cost to Haul and Dispose ($/well)
213,482
From Worksheet No. 3
Unit Cost to Grind and Iniect ($/well)
205.822
...
From Worksheet No. 4
Weighted Average Per Well Cost ($/well)
205,822
...
Assumes 80% hauls and 20% injects
Weighted Average Unit Cost ($/bbl)
143
...
No. Wells
18
...
SUBTOTAL ANNUAL GOM ZD COST ($)
3.704.788
3.704.788
Per-well costs x no. of wells
Total Annual GOM Costs for Zero Discharge
3.796.143
A-32
-------
APPENDIX VIII-4
POLLUTANT LOADINGS AND REDUCTIONS CALCULATIONS
A-33
-------
Summary Pollutant Loadings and Reductions for SBF-Cuttings from Existing Sources
(Assuming Gulf of Mexico Well Counts for "20% Convert" Scenario)
Baseline Pollutant Loadings: Total Annual
Baseline Technology
GOM
CA-Offshore
AK-Cook
Tnlet
Total
Discharge with 11% retention on cuttings
159,103,752
0
0
0
Zero Discharge
0
0
0
0
TOTATT,
1 59 103 75?
0
0
159 103 75?
Compliance Pollutant Loadings: Total Annual
Option
GOM
CA-Offshore
AK-Cook
Total
Tnlet
Discharge with 7% retention on cuttings
163,851,174
0
590,550
164,441,724
Zero Discharge
0
0
0
0
Incremental Pollutant Reductions: Total Annual
Option
GOM
CA-Offshore AK-Cook
Tnlet
Total
Discharge with 7% retention on cuttings
Zero Discharge
(4,747,422)
159 103 75?
0 (590,550)
0 0
(5,337,972)
0
159 103 75?
A-35
-------
Preceeding Page Blank
Gulf of Mexico Annual Loadings and Reductions Summary for Existing Sources (lbs per year)
Well Counts for "20% Convert" Scenario
Number of Wells:
Deep Water
Development Exploratory
Using SBF (current= 11 %): 18 57
Using OBF (current=0 dis): 0 0
Gulf of Mexico Baseline Pollutant Loadings Summary
Baseline
Technology
Deep Water (>1,000 ft)
Shallow Water (<1,000 ft)
Total
Notes
Development
Exploratory
Development
Exploratory
Discharge w/11% retention
Zero Discharge
17,639,334
124,194,108
7,770,960
0
9,499,350
0
159,103,752
0
94 SBF wells; From Worksheet No.s 1-4
23 OBF wells; From Worksheet No.s 7-8
Gulf of Mexico BAT Pollutant Loadings Summary
Option (a)
Deep Water (>1,000 ft)
Shallow Water (<1,000 ft)
Total
Notes
Development
Exploratory
Development
Exploratory
Discharge w/ 7% retention
Zero Discharge
16,085,988
0
113,257,176
0
15,944,850
0
18,563,160
0
163,851,174
0
94 SBF plus 23 OBF wells; From Worksheet No.s 5-8
94 SBF wells; From Worksheet No.s 9-12
Gulf of Mexico Incremental Pollutant Reductions Summary (b)
Option (a)
Deep Water (>1,000 ft)
Shallow Water (<1,000 ft)
Total
Notes
Development
Exploratory
Development
Exploratory
Discharge w/ 7% retention
Zero Discharge
1,553,364
17,639,334
10,936,932
124,194,108
(8,173,902)
7,770,960
(9,063,810)
9,499,350
(4,747,416)
159,103,752
Difference between BAT loadings and baseline loadings
for 94 SBF and 23 OBF wells; negative incremental
reductions indicate loadings.
Difference between zero discharge BAT loadings and
baseline discharge loadings for 94 wells currently
using SBF.
(a) For the discharge option, it is assumed that wells currently using OBF will switch to SBF.
(b) Incremental Reductions = BAT Loadings - Baseline Loadings.
Shallow Water
Development Exploratory Total
12 7 94
15 8 23
A-36
-------
California Offshore Loadings and Reductions Summary for Existing Sources (lbs)
Number of Wells:
Deep Water Shallow Water
Development Exploratory Development Exploratory
(using SBF): 11 0 1 0
California Offshore Baseline Pollutant Loadings Summary
Option
Deep Water (>1,000 ft)
Shallow Water (<1,000 ft)
Total
Notes
Development
Exploratory
Development
Exploratory
Zero Discharge
0
0
0
All California Offshore wells are currently at zero discharge.
California Offshore BAT Pollutant Loadings Summary
Option
Deep Water (>1,000 ft)
Shallow Water (<1,000 ft)
Total
Notes
Development
Exploratory
Development
Exploratory
Discharge
Zero Discharge
9,830,326
0
--
590,550
0
--
10,420,876
0
From Worksheet No.s 5 and 7.
From Worksheet No.s 9 and 11.
California Offshore Incremental Pollutant Reductions Summary (a)
Option
Deep Water (>1,000 ft)
Shallow Water (<1,000 ft)
Total
Notes
Development
Exploratory
Development
Exploratory
Discharge
Zero Discharge
(9,830,326)
0
(590,550)
0
(10,420,876)
0
Difference between BAT loadings and baseline loadings;
negative incremental reductions indicate loadings.
No reduction between baseline and zero discharge.
(a) Incremental Reductions = BAT Loadings - Baseline Loadings.
A-37
-------
Cook Inlet, Alaska Loadings and Reductions Summary for Existing Sources (lbs)
Number of Wells:
Deep Water Shallow Water
Development Exploratory Development Exploratory
(using SBF): 0 0 10
Cook Inlet, Alaska Baseline Pollutant Loadings Summary
Option
Deep Water (>1,000 ft)
Shallow Water (<1,000 ft)
Total
Notes
Development
Exploratory
Development
Exploratory
Zero Discharge
0
0
All Cook Inlet, Alaska wells are currently at zero discharge.
Cook Inlet, Alaska BAT Pollutant Loadings Summary
Option
Deep Water (>1,000 ft)
Shallow Water (<1,000 ft)
Total
Notes
Development
Exploratory
Development
Exploratory
Discharge
Zero Discharge
--
--
590,550
0
--
590,550
0
From Worksheet No. 7.
From Worksheet No 11.
Cook Inlet, Alaska Incremental Pollutant Reductions Summary (a)
Option
Deep Water (>1,000 ft)
Shallow Water (<1,000 ft)
Total
Notes
Development
Exploratory
Development
Exploratory
Discharge
Zero Discharge
(590,550)
0
(590,550)
0
Difference between BAT loadings and baseline loadings;
negative incremental reductions indicate loadings.
No reduction between baseline and zero discharge.
(a) Incremental Reductions = BAT Loadings - Baseline Loadings; negative incremental reductions represent loadings.
A-38
-------
NSPS Annual Loadings and Reductions Summary for New Sources (lbs per year)
Number of Wells:
Deep Water Shallow Water
Development Exploratory Development Exploratory Total
GOM NSPS wells: 18 0 1 0 19
NSPS Baseline Pollutant Loadings Summary
Baseline
Technology
Deep Water (>1,000 ft)
Shallow Water (<1,000 ft)
Total
Notes
Development
Exploratory
Development
Exploratory
Discharge w/11% retention
17,639,334
647,580
18,286,914
19 SBF wells; From Worksheet No.s 1 and 3.
NSPS BAT Pollutant Loadings Summary
Option (a)
Deep Water (>1,000 ft)
Shallow Water (<1,000 ft)
Total
Notes
Development
Exploratory
Development
Exploratory
Discharge w/ 7%
Zero Discharge
16,085,988
0
--
590,550
0
--
16,676,538
0
From Worksheet No.s 5 and 7.
From Worksheet No.s 9 and 11.
NSPS Incremental Pollutant Reductions Summary (a)
Option (a)
Deep Water (>1,000 ft)
Shallow Water (<1,000 ft)
Total
Notes
Development
Exploratory
Development
Exploratory
Discharge w/ 7%
Zero Discharge
1,553,364
17,639,334
--
57,030
647,580
--
1,610,394
18,286,914
Difference between BAT loadings and baseline loadings
Difference between zero discharge BAT loadings.
(a) Incremental Reductions = BAT Loadings - Baseline Loadings.
A-39
-------
WORKSHEET 1: Baseline Loadings
Deep Water Development Well
Technology = Discharge Assuming 11% (wt) Retention on Discharged Cuttings and 0.2% (vol.) Crude Contamination
Dry Cuttings Generated per Well = 778,050 lbs
Whole Drilling Fluid Discharged per Well = 588 bbls
Pollutant Name
Pollutants in
Pollutant
Reductions
Drilling Waste
Loadings per Well
Per Well
Conventional Pollutants
lbs
lbs
TSS (as barite)
78,414
0
TSS (as dry cuttings)
778,050
0
I'SS dotal 1
856,464
0
Total Oil (base lliiid plus crude)
112,075
0
Priority Pollutant Organics
lbs/bbl drilling fluid
Naphthalene
0.0010052
0.5911
0.0000
Fluorene
0.0005483
0.3224
0.0000
Phenanthrene
0.0013004
0.7647
0.0000
Phenol
7.22e-08
0.0000
0.0000
Total Priority Pollutant Oraanics
1.6782
o.oooo
Priority Pollutants, Metals
lbs/lb barite
Cadmium
0.0000011
0.0863
0.0000
Mercury
0.0000001
0.0078
0.0000
Antimony
0.0000057
0.4470
0.0000
Arsenic
0.0000071
0.5567
0.0000
Berylium
0.0000007
0.0549
0.0000
Chromium
0.0002400
18.8194
0.0000
Copper
0.0000187
1.4663
0.0000
Lead
0.0000351
2.7523
0.0000
Nickel
0.0000135
1.0586
0.0000
Selenium
0.0000011
0.0863
0.0000
Silver
0.0000007
0.0549
0.0000
Thallium
0.0000012
0.0941
0.0000
Zinc
0.0002005
15.7220
0.0000
Total Priority Pollutant Metals
41.21
0.00
Non-Conventional Metals
lbs/lb barite
Aluminum
0.0090699
711.2071
0.0000
Barium
0.1200000
9,409.6800
0.0000
Iron
0.0153443
1,203.2079
0.0000
Tin
0.0000146
1.1448
0.0000
Titanium
0.0000875
6.8612
0.0000
Non-Conventional Orsanics
lbs/bbl drilling fluid
Alkylated benzenes
0.0056587
3.3273
0.0000
Alkylated naphthalenes
0.0531987
31.2808
0.0000
Alkylated fluorenes
0.0064038
3.7654
0.0000
Alkylated phenanthrenes
0.0080909
4.7574
0.0000
Alkylated phenlos
0.0000006
0.0004
0.0000
Total biphenyls
0.0105160
6.1834
0.0000
Total diben/othiophenes
0.0000092
0.0054
0.0000
Total Non-Conventional Pollutants
1 1.381.42
0.00
Total Loadings and Reductions (lbs per well)
979.963
0
A-40
-------
WORKSHEET 2: Baseline
Deep Water Exploratory Well
Technology = Discharge Assuming 11% (wt) Retention on Discharged Cuttings and 0.2% (vol.) Crude Contamination
Dry Cuttings Generated per Well = 1,729,910 lbs
Whole Drilling Fluid Discharged per Well = 1308 bbls
Avg. Cone, of
Pollutant
Pollutant Name
Pollutants in
Loadings per Well
Reductions
Drilling Waste
Per Well
Conventional Pollutants
lbs
lbs
TSS (as barite)
174,346
0
TSS (as dry cuttings)
1,729,910
0
I'SS (total)
1,904,256
0
Total Oil (base lluid plus crude)
249.187
0
Prioritv Pollutant Orsanics
lbs/bbl drilling fluid
Naphthalene
0.0010052
1.3148
0.0000
Fluorene
0.0005483
0.7172
0.0000
Phenanthrene
0.0013004
1.7010
0.0000
Phenol
7.22e-08
0.0001
0.0000
Total Priority Pollutant Oraanics
3.7331
0.0000
Prioritv Pollutants. Metals
lbs/lb barite
Cadmium
0.0000011
0.1918
0.0000
Mercury
0.0000001
0.0174
0.0000
Antimony
0.0000057
0.9938
0.0000
Arsenic
0.0000071
1.2379
0.0000
Berylium
0.0000007
0.1220
0.0000
Chromium
0.0002400
41.8430
0.0000
Copper
0.0000187
3.2603
0.0000
Lead
0.0000351
6.1195
0.0000
Nickel
0.0000135
2.3537
0.0000
Selenium
0.0000011
0.1918
0.0000
Silver
0.0000007
0.1220
0.0000
Thallium
0.0000012
0.2092
0.0000
Zinc
0.0002005
34.9564
0.0000
Total Priority Pollutant Metals
91.62
0.00
Non-Conventional Metals
lbs/lb barite
Aluminum
0.0090699
1,581.3008
0.0000
Barium
0.1200000
20,921.5200
0.0000
Iron
0.0153443
2,675.2173
0.0000
Tin
0.0000146
2.5455
0.0000
Titanium
0.0000875
15.2553
0.0000
Non-Conventional Orsanics
lbs/bbl drilling fluid
Alkylated benzenes
0.0056587
7.4016
0.0000
Alkylated naphthalenes
0.0531987
69.5839
0.0000
Alkylated fluorenes
0.0064038
8.3762
0.0000
Alkylated phenanthrenes
0.0080909
10.5829
0.0000
Alkylated phenlos
0.0000006
0.0008
0.0000
Total biphenyls
0.0105160
13.7550
0.0000
Total diben/othiophenes
0.0000092
0.0120
0.0000
Total Non-Conventional Pollutants
25.305.55
0.00
Total Loadings and Reductions (lbs per well)
2.178.844
0
A-41
-------
WORKSHEET 3: Baseline Loadings
Shallow Water Development Well
Technology = Discharge Assuming 11% (wt) Retention on Discharged Cuttings and 0.2% (vol.) Crude Contamination
Dry Cuttings Generated per Well = 514,150 lbs
Whole Drilling Fluid Discharged per Well = 389 bbls
Avg. Cone, of
Pollutant
Pollutant Name
Pollutants in
Loadings per Well
Reductions
Drilling Waste
Per Well
Conventional Pollutants
lbs
lbs
TSS (as barite)
51,818
0
TSS (as dr\ cuttiims)
514,150
0
TSS (total)
565.968
0
Total Oil (base lluid plus crude)
74.062
0
Prioritv Pollutant Orsanics
lbs/bbl drilling fluid
Naphthalene
0.0010052
0.3910
0.0000
Fluorene
0.0005483
0.2133
0.0000
Phenanthrene
0.0013004
0.5059
0.0000
Phenol
7.22e-08
0.0000
0.0000
Total Priority Pollutant Oraanics
1.1102
().()()()()
Prioritv Pollutants. Metals
lbs/lb barite
Cadmium
0.0000011
0.0570
0.0000
Mercury
0.0000001
0.0052
0.0000
Antimony
0.0000057
0.2954
0.0000
Arsenic
0.0000071
0.3679
0.0000
Berylium
0.0000007
0.0363
0.0000
Chromium
0.0002400
12.4363
0.0000
Copper
0.0000187
0.9690
0.0000
Lead
0.0000351
1.8188
0.0000
Nickel
0.0000135
0.6995
0.0000
Selenium
0.0000011
0.0570
0.0000
Silver
0.0000007
0.0363
0.0000
Thallium
0.0000012
0.0622
0.0000
Zinc
0.0002005
10.3895
0.0000
Total Priority Pollutant Metals
27.23
0.00
Non-Conventional Metals
lbs/lb barite
Aluminum
0.0090699
469.9841
0.0000
Barium
0.1200000
6,218.1600
0.0000
Iron
0.0153443
795.1109
0.0000
Tin
0.0000146
0.7565
0.0000
Titanium
0.0000875
4.5341
0.0000
Non-Conventional Orsanics
lbs/bbl drilling fluid
Alkylated benzenes
0.0056587
2.2012
0.0000
Alkylated naphthalenes
0.0531987
20.6943
0.0000
Alkylated fluorenes
0.0064038
2.4911
0.0000
Alkylated phenanthrenes
0.0080909
3.1473
0.0000
Alkylated phenlos
0.0000006
0.0002
0.0000
Total biphenyls
0.0105160
4.0907
0.0000
Total diben/othiophenes
0.0000092
0.0036
0.0000
Total Non-Conventional Pollutants
7.521.17
0.00
Total Loadings and Reductions (lbs per well)
647.580
0
A-42
-------
WORKSHEET 4: Baseline Loadings
Shallow Water Exploratory Well
Technology = Discharge Assuming 11% (wt) Retention on Discharged Cuttings and 0.2% (vol.) Crude
Dry Cuttings Generated per Well =
1,077,440
lbs
Whole Drilling Fluid Discharged per Well =
814
bbls
Avg. Cone, of
Pollutant
Pollutant Name
Pollutants in
Loadings per Well
Reductions
Drilling Waste
Per Well
Conventional Pollutants
lbs
lbs
TSS (as barite)
108,588
0
TSS (as dry cuttings)
1.077.440
0
I'SS (total)
1,186.028
0
Total Oil (base lluid plus crude)
155.202
0
Prioritv Pollutant Orsanics
lbs/bbl drilling fluid
Naphthalene
0.0010052
0.8182
0.0000
Fluorene
0.0005483
0.4463
0.0000
Phenanthrene
0.0013004
1.0586
0.0000
Phenol
7.22e-08
0.0001
0.0000
Total Priority Pollutant Oraanics
2.3232
().()()()()
Prioritv Pollutants. Metals
lbs/lb barite
Cadmium
0.0000011
0.1194
0.0000
Mercury
0.0000001
0.0109
0.0000
Antimony
0.0000057
0.6190
0.0000
Arsenic
0.0000071
0.7710
0.0000
Berylium
0.0000007
0.0760
0.0000
Chromium
0.0002400
26.0611
0.0000
Copper
0.0000187
2.0306
0.0000
Lead
0.0000351
3.8114
0.0000
Nickel
0.0000135
1.4659
0.0000
Selenium
0.0000011
0.1194
0.0000
Silver
0.0000007
0.0760
0.0000
Thallium
0.0000012
0.1303
0.0000
Zinc
0.0002005
21.7719
0.0000
Total Priority Pollutant Metals
57.06
0.00
Non-Conventional Metals
lbs/lb barite
Aluminum
0.0090699
984.8823
0.0000
Barium
0.1200000
13,030.5600
0.0000
Iron
0.0153443
1,666.2068
0.0000
Tin
0.0000146
1.5854
0.0000
Titanium
0.0000875
9.5015
0.0000
Non-Conventional Orsanics
lbs/bbl drilling fluid
Alkylated benzenes
0.0056587
4.6062
0.0000
Alkylated naphthalenes
0.0531987
43.3038
0.0000
Alkylated fluorenes
0.0064038
5.2127
0.0000
Alkylated phenanthrenes
0.0080909
6.5860
0.0000
Alkylated phenlos
0.0000006
0.0005
0.0000
Total biphenyls
0.0105160
8.5600
0.0000
Total diben/othiophenes
0.0000092
0.0074
0.0000
Total Non-Conventional Pollutants
15.761.01
0.00
Total Loadings and Reductions (lbs per well)
1.357.050
0
A-43
-------
WORKSHEET 5: Discharge Option Loadings and Incremental
Deep Water Development Well
Technology = Discharge Assuming 7% (wt) Retention on Discharged Cuttings and 0.2% (vol) Crude Contamination
Dry Cuttings Generated per Well = 778,050 lbs
Whole Drilling Fluid Discharged Per Well = 337 bbls
Avg. Cone, of
Pollutant Loadings ner Well (\bs)
Pollutant Name
Pollutants in
Current Practice
Discharge at
Reductions
Drilling Waste
(11 % Retention)
7% Retention
Per Well
Conventional Pollutants
TSS (as barite)
78,414
44,886
33,528
TSS (as dr\ cuttiims)
778,050
778,050
0
'I'SS (total)
856,464
822.936
33.528
Total Oil (base lluid plus crude)
112.075
64.190
47.885
Prioritv Pollutants. Orsanics
lbs/bbl drilling fluid
Naphthalene
0.0010052
0.5911
0.3388
0.2523
Fluorene
0.0005483
0.3224
0.1848
0.1376
Phenanthrene
0.0013004
0.7647
0.4382
0.3264
Phenol
7.22e-08
0.0000
0.0000
0.0000
Total Priority Pollutants. Or»anics
1.6782
0.9618
0.7164
Prioritv Pollutants. Metals
lbs/lb barite
Cadmium
0.0000011
0.0863
0.0494
0.0369
Mercury
0.0000001
0.0078
0.0045
0.0034
Antimony
0.0000057
0.4470
0.2559
0.1911
Arsenic
0.0000071
0.5567
0.3187
0.2380
Berylium
0.0000007
0.0549
0.0314
0.0235
Chromium
0.0002400
18.8194
10.7726
8.0467
Copper
0.0000187
1.4663
0.8394
0.6270
Lead
0.0000351
2.7523
1.5755
1.1768
Nickel
0.0000135
1.0586
0.6060
0.4526
Selenium
0.0000011
0.0863
0.0494
0.0369
Silver
0.0000007
0.0549
0.0314
0.0235
Thallium
0.0000012
0.0941
0.0539
0.0402
Zinc
0.0002005
15.7220
8.9996
6.7224
Total Priority Pollutant Metals
41.21
23.59
17.62
Non-Conventional Metals
lbs/lb barite
Aluminum
0.0090699
711.2071
407.1115
304.0956
Barium
0.1200000
9,409.6800
5,386.3200
4,023.3600
Iron
0.0153443
1,203.2079
688.7442
514.4637
Tin
0.0000146
1.1448
0.6553
0.4895
Titanium
0.0000875
6.8612
3.9275
2.9337
Non-Conventional Orsanics
lbs/bbl drilling fluid
Alkylated benzenes
0.0056587
3.3273
1.9070
1.4203
Alkylated naphthalenes
0.0531987
31.2808
17.9280
13.3529
Alkylated fluorenes
0.0064038
3.7654
2.1581
1.6074
Alkylated phenanthrenes
0.0080909
4.7574
2.7266
2.0308
Alkylated phenols
0.0000006
0.0004
0.0002
0.0002
Total biphenyls
0.0105160
6.1834
3.5439
2.6395
Total diben/othiophenes
0.0000092
0.0054
0.0031
0.0023
Total Non-Conventional Pollutants
1 1.381.42
6.515.03
4.866
Total Loadings and Reductions (lbs per
979.963
893.666
86.298
A-44
-------
WORKSHEET 6: Discharge Option Loadings and Incremental Reductions
Deep Water Exploratory Well
Technology = Discharge Assuming 7% (wt) Retention on Discharged Cuttings and 0.2% (vol) Crude Contamination
Dry Cuttings Generated per Well = 1,729,910 lbs
Whole Drilling Fluid Discharged Per Well = 749 bbls
Avg. Cone, of
Pollutant Loadings ner Well (lbs)
Pollutant Name
Pollutants in
Current
Discharge at
Reductions
Drilling Waste
(11 % Retention)
7% Retention
Per Well
Conventional Pollutants
TSS (as barite)
174,346
99,799
74,547
TSS (as dr\ cuttings)
1.729,910
1.729,910
0
'I'SS (total)
1.904.256
1,829.709
74,547
Total Oil (base Iluid plus crude)
249.187
142.719
106.468
Prioritv Pollutants. Oreanics
lbs/bbl drilling fluid
Naphthalene
0.0010052
1.3148
0.7529
0.5619
Fluorene
0.0005483
0.7172
0.4107
0.3065
Phenanthrene
0.0013004
1.7010
0.9740
0.7269
Phenol
7.22e-08
0.0001
0.0001
0.0000
Total Prioritv Pollutants. Omanics
3.7331
2.1377
1.5954
Prioritv Pollutants. Metals
lbs/lb barite
Cadmium
0.0000011
0.1918
0.1098
0.0820
Mercury
0.0000001
0.0174
0.0100
0.0075
Antimony
0.0000057
0.9938
0.5689
0.4249
Arsenic
0.0000071
1.2379
0.7086
0.5293
Berylium
0.0000007
0.1220
0.0699
0.0522
Chromium
0.0002400
41.8430
23.9518
17.8913
Copper
0.0000187
3.2603
1.8662
1.3940
Lead
0.0000351
6.1195
3.5029
2.6166
Nickel
0.0000135
2.3537
1.3473
1.0064
Selenium
0.0000011
0.1918
0.1098
0.0820
Silver
0.0000007
0.1220
0.0699
0.0522
Thallium
0.0000012
0.2092
0.1198
0.0895
Zinc
0.0002005
34.9564
20.0097
14.9467
Total Priority Pollutant Metals
91.62
52.44
39.17
Non-Conventional Metals
lbs/lb barite
Aluminum
0.0090699
1,581.3008
905.1670
676.1338
Barium
0.1200000
20,921.5200
11,975.8800
8,945.6400
Iron
0.0153443
2,675.2173
1,531.3458
1,143.8715
Tin
0.0000146
2.5455
1.4571
1.0884
Titanium
0.0000875
15.2553
8.7324
6.5229
Non-Conventional Orsanics
lbs/bbl drilling fluid
Alkylated benzenes
0.0056587
7.4016
4.2384
3.1632
Alkylated naphthalenes
0.0531987
69.5839
39.8458
29.7381
Alkylated fluorenes
0.0064038
8.3762
4.7965
3.5797
Alkylated phenanthrenes
0.0080909
10.5829
6.0601
4.5228
Alkylated phenols
0.0000006
0.0008
0.0005
0.0004
Total biphenyls
0.0105160
13.7550
7.8765
5.8785
Total diben/othiophenes
0.0000092
0.0120
0.0069
0.0051
Total Non-Conventional Pollutants
25.305.55
14.485.41
10.820
Total Loadings and Reductions fibs per
2.178.844
1.986.968
191.876
A-45
-------
WORKSHEET 7: Discharge Option Loadings and Incremental Reductions
Shallow Water Development Well
Technology = Discharge Assuming 7% (wt) Retention on Discharged Cuttings and 0.2% (vol) Crude Contamination
SBF-using Facilities = Change from 11% to 7% retention on discharged cuttings
OBF-using Facilities = Change from zero discharge to 7% retention on discharged cuttings
Dry Cuttings Generated per Well = 514,150 lbs
Whole Drilling Fluid Discharged Per Well = 223 bbls
Avg. Cone, of
Pollutant Loadings per Well (lbs)
SBF-using Well
OBF-using Well
Pollutant Name
Pollutants in
Current Practice, SBF
Current Practice, OBF
Discharge at
Reductions
Reductions
Drilling Waste
Wells (ll%Retention)
Wells (0 discharge)
7% Retention
Per Well
Per Well
Conventional Pollutants
TSS (as barite)
51,818
0
29,661
22,157
(29,661)
TSS (as dry cullings)
514.150
0
514.150
0
(514.150)
TSS (lolal)
565.968
0
543.811
22.157
(543.811)
Tolal Oil (base Iluid plus crude)
74.062
0
42.418
31.644
(42.418)
Priority Pollutants, Organics
lbs/bbl drilling fluid
Naphthalene
0.0010052
0.3910
0
0.2242
0.1669
(0.2242)
Fluorene
0.0005483
0.2133
0
0.1223
0.0910
(0.1223)
Phenanthrene
0.0013004
0.5059
0
0.2900
0.2159
(0.2900)
Phenol
7.77e-08
().()()()()
0
().()()()()
().()()()()
(0.0000)
Total Priorilv Pollulanls. ()n»anics
1.1102
0
0.6364
0.4738
(0.6364)
Priority Pollutants, Metals
lbs/lb barite
Cadmium
0.0000011
0.0570
0
0.0326
0.0244
(0.0326)
Mercury
0.0000001
0.0052
0
0.0030
0.0022
(0.0030)
Antimony
0.0000057
0.2954
0
0.1691
0.1263
(0.1691)
Arsenic
0.0000071
0.3679
0
0.2106
0.1573
(0.2106)
Berylium
0.0000007
0.0363
0
0.0208
0.0155
(0.0208)
Chromium
0.0002400
12.4363
0
7.1186
5.3177
(7.1186)
Copper
0.0000187
0.9690
0
0.5547
0.4143
(0.5547)
Lead
0.0000351
1.8188
0
1.0411
0.7777
(1.0411)
Nickel
0.0000135
0.6995
0
0.4004
0.2991
(0.4004)
Selenium
0.0000011
0.0570
0
0.0326
0.0244
(0.0326)
Silver
0.0000007
0.0363
0
0.0208
0.0155
(0.0208)
Thallium
0.0000012
0.0622
0
0.0356
0.0266
(0.0356)
Zinc
0.0002005
10.3895
0
5.9470
4.4425
(5.9470)
77.7.3
0
15.59
11.64
(15.591
Non-Conventional Metals
lbs/lb barite
Aluminum
0.0090699
469.9841
0
269.0223
200.9618
(269.0223)
Barium
0.1200000
6,218.1600
0
3,559.3200
2,658.8400
(3,559.3200)
Iron
0.0153443
795.1109
0
455.1273
339.9837
(455.1273)
Tin
0.0000146
0.7565
0
0.4331
0.3235
(0.4331)
0.0000875
4.5341
0
7.5953
1.9387
(2.59531
Non-Conventional Organics
lbs/bbl drilling fluid
Alkylated benzenes
0.0056587
2.2012
0
1.2619
0.9393
(1.2619)
Alkylated naphthalenes
0.0531987
20.6943
0
11.8633
8.8310
(11.8633)
Alkylated fluorenes
0.0064038
2.4911
0
1.4280
1.0630
(1.4280)
Alkylated phenanthrenes
0.0080909
3.1473
0
1.8043
1.3431
(1.8043)
Alkylated phenols
0.0000006
0.0002
0
0.0001
0.0001
(0.0001)
Total biphenyls
0.0105160
4.0907
0
2.3451
1.7457
(2.3451)
Tolal dibenzolhiophenes
0.0000092
0.0036
0
0.0020
0.0015
(0.0020)
7 ¦>{)
3 ">16
a 7(»
Total Loadings and Reductions (lbs per well)
647,580
0
590,550
57,029
(590,550)
-------
WORKSHEET 8: Discharge Option Loadings and Incremental Reductions
Shallow Water Exploratory Well
Technology = Discharge Assuming 7% (wt) Retention on Discharged Cuttings and 0.2% (vol) Crude Contamination
SBF-using Facilities = Change from 11% to 7% retention on discharged cuttings
OBF-using Facilities = Change from zero discharge to 7% retention on discharged cuttings
Dry Cuttings Generated per Well = 1,077,440 lbs
Whole Drilling Fluid Discharged Per Well = 466 bbls
Avg. Cone, of
Pollutant Loadings per Well (lbs)
SBF-using Well
OBF-using Well
Pollutant Name
Pollutants in
Current Practice, SBF
Current Practice, OBF
Discharge at
Reductions
Loadings
Drilling Waste
Wells (11% Retention)
Wells (0 discharge)
7% Retention
Per Well
Per Well
Conventional Pollutants
TSS (as barite)
108,588
0
62,158
46,430
(62,158)
TSS (as dry cuttings)
1,077,440
0
1,077,440
0
(1,077,440)
TSS (total)
1.186.028
0
1.139.598
46.430
(1.139.598)
Total Oil (base lluid plus crude)
155.202
0
88.890
66.312
(88.890)
Priority Pollutants, Organics
lbs/bbl drilling fluid
Naphthalene
0.0010052
0.8182
0
0.4684
0.3498
(0.4684)
Fluorene
0.0005483
0.4463
0
0.2555
0.1908
(0.2555)
Phenanthrene
0.0013004
1.0586
0
0.6060
0.4526
(0.6060)
Phenol
7.22e-08
0.0001
0
0.0000
0.0000
(0.0000)
Total Priority Pollutants. ()rganics
2.3232
0
1.3300
0.9932
(1.3300)
Priority Pollutants, Metals
lbs/lb barite
Cadmium
0.0000011
0.1194
0
0.0684
0.0511
(0.0684)
Mercury
0.0000001
0.0109
0
0.0062
0.0046
(0.0062)
Antimony
0.0000057
0.6190
0
0.3543
0.2647
(0.3543)
Arsenic
0.0000071
0.7710
0
0.4413
0.3297
(0.4413)
Berylium
0.0000007
0.0760
0
0.0435
0.0325
(0.0435)
Chromium
0.0002400
26.0611
0
14.9179
11.1432
(14.9179)
Copper
0.0000187
2.0306
0
1.1624
0.8682
(1.1624)
Lead
0.0000351
3.8114
0
2.1817
1.6297
(2.1817)
Nickel
0.0000135
1.4659
0
0.8391
0.6268
(0.8391)
Selenium
0.0000011
0.1194
0
0.0684
0.0511
(0.0684)
Silver
0.0000007
0.0760
0
0.0435
0.0325
(0.0435)
Thallium
0.0000012
0.1303
0
0.0746
0.0557
(0.0746)
Zinc
0.0002005
21.7719
0
12.4627
9.3092
(12.4627)
Total Priority Pollutant Metals
57.06
0
32.66
24.40
(32.66)
Non-Conventional Metals
lbs/lb barite
Aluminum
0.0090699
984.8823
0
563.7668
421.1155
(563.7668)
Barium
0.1200000
13,030.5600
0
7,458.9600
5,571.6000
(7,458.9600)
Iron
0.0153443
1,666.2068
0
953.7710
712.4358
(953.7710)
Tin
0.0000146
1.5854
0
0.9075
0.6779
(0.9075)
Titanium
0.0000875
9.5014
0
5.4388
4.0626
(5.4388)
Non-Conventional Organics
lbs/bbl drilling fluid
Alkylated benzenes
0.0056587
4.6062
0
2.6369
1.9692
(2.6369)
Alkylated naphthalenes
0.0531987
43.3038
0
24.7906
18.5132
(24.7906)
Alkylated fluorenes
0.0064038
5.2127
0
2.9842
2.2285
(2.9842)
Alkylated phenanthrenes
0.0080909
6.5860
0
3.7703
2.8156
(3.7703)
Alkylated phenols
0.0000006
0.0005
0
0.0003
0.0002
(0.0003)
Total biphenyls
0.0105160
8.5600
0
4.9005
3.6596
(4.9005)
Total dibenzothiophenes
0.0000092
0.0074
0
0.0043
0.0032
(0.0043)
Total Non-Conventional Pollutants
15.761.01
0
9,021.93
6.739
(9.021.9313)
Total Loadings and Reductions (lbs per well)
1,357,050
0
1,237,544
119,506
(1,237,544)
-------
WORKSHEET 9: Zero Discharge Option Incremental Reductions
Deep Water Development Well
Technology = Zero Discharge Assuming 11% (wt) Retention on Discharged Cuttings and 0.2% Crude Contamination
Dry Cuttings Generated per Well = 778,050 lbs
Whole Drilling Fluid Disposed per Well = 588 bbls
Avg. Cone, of
Pollutant Loadings per Well (lbs)
Pollutant Name
Pollutants in
Current Practice
Zero
Reductions
Drilling Waste
(11 % Retention)
Discharge
Per Well
Conventional Pollutants
TSS (as barite)
78,414
0
78,414
TSS (as dry cuttings)
778,050
0
778,050
I'SS (total)
856,464
0
856,464
Total Oil (base lluid plus crude)
1 12.075
0
112.075
Priority Pollutant Organics
lbs/bbl drilling fluid
Naphthalene
0.0010052
0.5911
0.0000
0.5911
Fluorene
0.0005483
0.3224
0.0000
0.3224
Phenanthrene
0.0013004
0.7647
0.0000
0.7647
Phenol
7.22e-08
0.0000
0.0000
0.0000
Total Priority Pollutant Organics
1.6782
0.0000
1.6782
Priority Pollutants, Metals
lbs/lb barite
Cadmium
0.0000011
0.0863
0.0000
0.0863
Mercury
0.0000001
0.0078
0.0000
0.0078
Antimony
0.0000057
0.4470
0.0000
0.4470
Arsenic
0.0000071
0.5567
0.0000
0.5567
Berylium
0.0000007
0.0549
0.0000
0.0549
Chromium
0.0002400
18.8194
0.0000
18.8194
Copper
0.0000187
1.4663
0.0000
1.4663
Lead
0.0000351
2.7523
0.0000
2.7523
Nickel
0.0000135
1.0586
0.0000
1.0586
Selenium
0.0000011
0.0863
0.0000
0.0863
Silver
0.0000007
0.0549
0.0000
0.0549
Thallium
0.0000012
0.0941
0.0000
0.0941
Zinc
0.0002005
15.7220
0.0000
15.7220
Total Priority Pollutant Metals
41.21
0.00
41.21
Non-Conventional Metals
lbs/lb barite
Aluminum
0.0090699
711.2071
0.0000
711.2071
Barium
0.1200000
9,409.6800
0.0000
9,409.6800
Iron
0.0153443
1,203.2079
0.0000
1,203.2079
Tin
0.0000146
1.1448
0.0000
1.1448
Titanium
0.0000875
6.8612
0.0000
6.8612
Non-Conventional Organics
lbs/bbl drilling fluid
Alkylated benzenes
0.0056587
3.3273
0.0000
3.3273
Alkylated naphthalenes
0.0531987
31.2808
0.0000
31.2808
Alkylated fluorenes
0.0064038
3.7654
0.0000
3.7654
Alkylated phenanthrenes
0.0080909
4.7574
0.0000
4.7574
Alkylated phenlos
0.0000006
0.0004
0.0000
0.0004
Total biphenyls
0.0105160
6.1834
0.0000
6.1834
Total dibenzothiophenes
0.0000092
0.0054
0.0000
0.0054
Total Non-Conventional Pollutants
11,381.42
0.00
11.381
Total Loadings and Reductions (lbs per well)
979,963
0
979,963
A-48
-------
WORKSHEET 10: Zero Discharge Option Incremental Reductions
Deep Water Exploratory Well
Technology = Zero Discharge Assuming 11% (wt) Retention on Discharged Cuttings and 0.2% Crude Contamination
Dry Cuttings Generated per Well = 1,729,910 lbs
Whole Drilling Fluid Disposed per Well = 1308 bbls
Avg. Cone, of
Pollutant Loadings per Well (lbs)
Pollutant Name
Pollutants in
Current Practice
Zero
Reductions
Drilling Waste
(11 % Retention)
Discharge
Per Well
Conventional Pollutants
TSS (as barite)
174,346
0
174,346
TSS (as dry cuttings)
1,729,910
0
1,729,910
TSS (total)
1.904.256
0
1,904.256
Total Oil (base lluid plus crude)
249,187
0
249,187
Priority Pollutant Organics
lbs/bbl drilling fluid
Naphthalene
0.0010052
1.3148
0.0000
1.3148
Fluorene
0.0005483
0.7172
0.0000
0.7172
Phenanthrene
0.0013004
1.7010
0.0000
1.7010
Phenol
7.22e-08
0.0001
0.0000
0.0001
Total Priority Pollutant Omanics
3.7331
0.0000
3.7331
Priority Pollutants, Metals
lbs/lb barite
Cadmium
0.0000011
0.1918
0.0000
0.1918
Mercury
0.0000001
0.0174
0.0000
0.0174
Antimony
0.0000057
0.9938
0.0000
0.9938
Arsenic
0.0000071
1.2379
0.0000
1.2379
Berylium
0.0000007
0.1220
0.0000
0.1220
Chromium
0.0002400
41.8430
0.0000
41.8430
Copper
0.0000187
3.2603
0.0000
3.2603
Tead
0.0000351
6.1195
0.0000
6.1195
Nickel
0.0000135
2.3537
0.0000
2.3537
Selenium
0.0000011
0.1918
0.0000
0.1918
Silver
0.0000007
0.1220
0.0000
0.1220
Thallium
0.0000012
0.2092
0.0000
0.2092
Zinc
0.0002005
34.9564
0.0000
34.9564
Total Priority Pollutant Metals
91.62
0.00
91.62
Non-Conventional Metals
lbs/lb barite
Aluminum
0.0090699
1,581.3008
0.0000
1,581.3008
Barium
0.1200000
20,921.5200
0.0000
20,921.5200
Iron
0.0153443
2,675.2173
0.0000
2,675.2173
Tin
0.0000146
2.5455
0.0000
2.5455
Titanium
0.0000875
15.2553
0.0000
15.2553
Non-Conventional Organics
lbs/bbl drilling fluid
Alkylated benzenes
0.0056587
7.4016
0.0000
7.4016
Alkylated naphthalenes
0.0531987
69.5839
0.0000
69.5839
Alkylated fluorenes
0.0064038
8.3762
0.0000
8.3762
Alkylated phenanthrenes
0.0080909
10.5829
0.0000
10.5829
Alkylated phenlos
0.0000006
0.0008
0.0000
0.0008
Total biphenyls
0.0105160
13.7550
0.0000
13.7550
Total dibenzothiophenes
0.0000092
0.0120
0.0000
0.0120
Total Non-Conventional Pollutants
25.305.55
0.00
25.306
Total Loadings and Reductions (lbs per well)
2,178,844
0
2,178,844
A-49
-------
WORKSHEET 11: Zero Discharge Option Incremental Reductions
Shallow Water Development Well
Technology = Zero Discharge Assuming 11% (wt) Retention on Discharged Cuttings and 0.2% Crude Contamination
Dry Cuttings Generated per Well = 514,150 lbs
Whole Drilling Fluid Disposed per Well = 389 bbls
Avg. Cone, of
Pollutant Loading
s per Well (lbs)
Pollutant Name
Pollutants in
Current Practice
Zero
Reductions
Drilling Waste
(11 % Retention)
Discharge
Per Well
Conventional Pollutants
TSS (as barite)
51,818
0
51,818
TSS ( as dr\ cutliimsi
514.150
0
514.150
I'SS (total)
565,968
0
565.968
Total Oil (base lluid plus crude)
74.062
0
74,062
Priority Pollutant Organics
lbs/bbl drilling fluid
Naphthalene
0.0010052
0.3910
0.0000
0.3910
Fluorene
0.0005483
0.2133
0.0000
0.2133
Phenanthrene
0.0013004
0.5059
0.0000
0.5059
Phenol
7.22e-08
0.0000
0.0000
0.0000
Total Priority Pollutant Or«anics
I.I 102
0.0000
I.I 102
Priority Pollutants, Metals
lbs/lb barite
Cadmium
0.0000011
0.0570
0.0000
0.0570
Mercury
0.0000001
0.0052
0.0000
0.0052
Antimony
0.0000057
0.2954
0.0000
0.2954
Arsenic
0.0000071
0.3679
0.0000
0.3679
Berylium
0.0000007
0.0363
0.0000
0.0363
Chromium
0.0002400
12.4363
0.0000
12.4363
Copper
0.0000187
0.9690
0.0000
0.9690
Lead
0.0000351
1.8188
0.0000
1.8188
Nickel
0.0000135
0.6995
0.0000
0.6995
Selenium
0.0000011
0.0570
0.0000
0.0570
Silver
0.0000007
0.0363
0.0000
0.0363
Thallium
0.0000012
0.0622
0.0000
0.0622
Zinc
0.0002005
10.3895
0.0000
10.3895
Total Priority Pollutant Metals
27.23
0.00
27.23
Non-Conventional Metals
lbs/lb barite
Aluminum
0.0090699
469.9841
0.0000
469.9841
Barium
0.1200000
6,218.1600
0.0000
6,218.1600
Iron
0.0153443
795.1109
0.0000
795.1109
Tin
0.0000146
0.7565
0.0000
0.7565
Titanium
0.0000875
4.5341
0.0000
4.5341
Non-Conventional Organics
lbs/bbl drilling fluid
Alkylated benzenes
0.0056587
2.2012
0.0000
2.2012
Alkylated naphthalenes
0.0531987
20.6943
0.0000
20.6943
Alkylated fluorenes
0.0064038
2.4911
0.0000
2.4911
Alkylated phenanthrenes
0.0080909
3.1473
0.0000
3.1473
Alkylated phenlos
0.0000006
0.0002
0.0000
0.0002
Total biphenyls
0.0105160
4.0907
0.0000
4.0907
Total dibenzothiophenes
().()()(10092
0.0036
0.0000
0.0036
Total Non-Conventional Pollutants
7.521.17
0.00
7.521
Tulal Loadings anil Rcdutliuus (lbs per well)
647,580
0
647,5NO
A-50
-------
WORKSHEET 12: Zero Discharge Option Incremental Reductions
Shallow Water Exploratory Well
Technology = Zero Discharge Assuming 11% (wt) Retention on Discharged Cuttings and 0.2% Crude Contamination
Dry Cuttings Generated per Well = 1,077,440 lbs
Whole Drilling Fluid Disposed per Well = 814 bbls
Avg. Cone, of
Pollutant Loadings per Well (lbs)
Pollutant Name
Pollutants in
Current Practice
Zero
Reductions
Drilling Waste
(11 % Retention)
Discharge
Per Well
Conventional Pollutants
TSS (as barite)
108,588
0
108,588
TSS (as dry cuttings)
1,077,440
0
1,077.440
TSS (total)
1,186,028
0
1.186,028
Total Oil (synthetic plus crude)
155,202
0
155.202
Priority Pollutant Organics
lbs/bbl drilling fluid
Naphthalene
0.0010052
0.8182
0.0000
0.8182
Fluorene
0.0005483
0.4463
0.0000
0.4463
Phenanthrene
0.0013004
1.0586
0.0000
1.0586
Phenol
7.22e-08
0.0001
0.0000
0.0001
Total Priority Pollutant Or«anics
2.3232
0.0000
2.3232
Priority Pollutants, Metals
lbs/lb barite
Cadmium
0.0000011
0.1194
0.0000
0.1194
Mercury
0.0000001
0.0109
0.0000
0.0109
Antimony
0.0000057
0.6190
0.0000
0.6190
Arsenic
0.0000071
0.7710
0.0000
0.7710
Berylium
0.0000007
0.0760
0.0000
0.0760
Chromium
0.0002400
26.0611
0.0000
26.0611
Copper
0.0000187
2.0306
0.0000
2.0306
Lead
0.0000351
3.8114
0.0000
3.8114
Nickel
0.0000135
1.4659
0.0000
1.4659
Selenium
0.0000011
0.1194
0.0000
0.1194
Silver
0.0000007
0.0760
0.0000
0.0760
Thallium
0.0000012
0.1303
0.0000
0.1303
Zinc
0.0002005
21.7719
0.0000
21.7719
Total Priority Pollutant Metals
57.06
().()()
57.06
Non-Conventional Metals
lbs/lb barite
Aluminum
0.0090699
984.8823
0.0000
984.8823
Barium
0.1200000
13,030.5600
0.0000
13,030.5600
Iron
0.0153443
1,666.2068
0.0000
1,666.2068
Tin
0.0000146
1.5854
0.0000
1.5854
Titanium
0.0000875
9.5015
0.0000
9.5014
Non-Conventional Organics
lbs/bbl drilling fluid
Alkylated benzenes
0.0056587
4.6062
0.0000
4.6062
Alkylated naphthalenes
0.0531987
43.3038
0.0000
43.3038
Alkylated fluorenes
0.0064038
5.2127
0.0000
5.2127
Alkylated phenanthrenes
0.0080909
6.5860
0.0000
6.5860
Alkylated phenlos
0.0000006
0.0005
0.0000
0.0005
Total biphenyls
0.0105160
8.5600
0.0000
8.5600
Total dibenzothiophenes
0.0000092
0.0074
0.0000
0.0074
Total Non-Conventional Pollutants
15,761.01
0.00
15,761
Total Loadings and Reductions (lbs per well)
1,357,050
0
1,357,050
A-51
-------
APPENDIX IX-1
BAT NON-WATER QUALITY ENVIRONMENTAL IMPACT
CALCULATIONS FOR EXISTING SOURCES
A-53
-------
A-54
-------
Summary BAT NWQEI of SBF Cuttings Management
Baseline NWQEI: Total Annual
Baseline Technology
Gulf of Mexico
Offshore California
Cook Inlet, Alaska
Total
Notes
Air
Emissions
(tons)
Fuel
Usage
(BOE), (a)
Air
Emissions
(tons)
Fuel
Usage
(BOE), (a)
Air
Emissions
(tons)
Fuel
Usage
(BOE), (a)
Air
Emissions
(tons)
Fuel
Usage
(BOE), (a)
Discharge with 11% retention of base
fluid on cuttings (b)
0
0
NA
NA
NA
NA
0.00
0.00
Zero Discharge: current OBF
users only (c)
47.92
3,432.82
36.61
2,120.72
2.08
285.15
86.61
5,838.68
From Worksheets No.s 1, 3, and 5
Total Baseline NWQEI
47.92
3,432.82
36.61
2,120.72
2.08
285.15
86.61
5,838.68
Compliance NWQEI: Total Annual
Option
Gulf of Mexico
Offshore California
Cook Inlet, Alaska
Total
Notes
Air
Emissions
(tons)
Fuel
Usage
(BOE), (a)
Air
Emissions
(tons)
Fuel
Usage
(BOE), (a)
Air
Emissions
(tons)
Fuel
Usage
(BOE), (a)
Air
Emissions
(tons)
Fuel
Usage
(BOE), (a)
Discharge Option (d)
12.54
3,034.95
0.76
187.07
0.01
4.02
13.30
3,226.03
From Worksheets No.s 7, 9, and 11
Zero Discharge Option (b)
338.55
24,124.56
NA
NA
NA
NA
338.55
24,124.56
From Worksheet No. 14
Incremental Compliance NWQEI Reductions: Total Annual
Gulf of Mexico
Offshore California
Cook Inlet, Alaska
Total
Air
Fuel
Air
Fuel
Air
Fuel
Air
Fuel
Emissions
Usage
Emissions
Usage
Emissions
Usage
Emissions
Usage
Option
(tons)
(BOE), (a)
(tons)
(BOE), (a)
(tons)
(BOE), (a)
(tons)
(BOE), (a)
Notes
Discharge Option (d)
35.38
397.87
35.86
1,933.65
2.07
281.13
73.31
2,612.65
Difference between total baseline and
compliance discharge option NWQIs
Zero Discharge Option (b)
(338.55)
(24,124.56)
0
0
0
0
(338.55)
(24,124.56)
Difference between discharge baseline
and zero discharge option NWQIs
(a) BOE (barrels of oil equivalent) is the sum of the volumes of diesel (by the factor 1 BOE = 42 gal diesel) and natural gas (1,000 scf = 0.178 BOE) estimated for each
compliance option.
(b) For Gulf of Mexico, NWQEI analysis conducted for 94 wells currently using SBF.
(c) Current zero discharge impacts apply only to wells drilled using OBF that are projected to convert to SBF: 23 Gulf of Mexico, 12 California and 1 Alaska well.
(d) Both OBF and SBF drilled wells are included in the discharge option NWQEI analysis as follows: GOM: 94 current SBF wells + 23 current OBF wells; CA: 12 current
OBF wells; AK: 1 current OBF well.
A-55
-------
Worksheet No. 1
Non-Water Quality Environmental Impacts: Baseline Current Practice
Region: Offshore Gulf of Mexico
Technology: Discharge of SBF cuttings via add-on cuttings "dryer" w/average achievable retention of 11% (wt) base fluid on cuttings
Zero Discharge of OBF cuttings via haul and land dispose (80%) plus on-site grinding and injection (20%)
Model Well Types: Deep Water Development, Deep Water Exploratory, Shallow Water Development, Shallow Water Exploratory
Air Emissions (tons)
Fuel Usage (BOE)
Wells Using SBF
Wells Using OBF
Wells Using SBF
Wells Using OBF
NWOEI
DWD
DWE
SWD
SWE
SWD
SWE
TOTAL
DWD
DWE
SWD
SWE
SWD
SWE
TOTAL
Notes
Discharge with 11% retention of base fluid
on cuttings (85% diesel, 15% nat. gas usage)
0.00
0.00
0.00
0.00
-
-
0.00
0.00
0.00
0.00
-
0.00
Hauling and Onshore Disposal
(diesel fuel source)
-
-
-
-
2.2358
3.2222
155.41
217.72
From Worksheet No. 7
Grinding and Injection
(diesel fuel source)
--
--
--
--
0.0850
0.1782
--
--
--
--
25.59
53.33
0.00
From Worksheet No. 8
Grinding and Injection
(natural gas fuel source)
-
-
-
-
0.0098
0.0205
-
-
-
-
38.59
80.47
0.00
From Worksheet No. 8
Weighted Average Grinding and Injection
-
-
-
-
0.0737
0.1545
-
-
-
-
27.54
57.40
0.00
Weighted avg. assumes 85% of wells use
diesel and 15% use nat. gas for
electricity generation
Weighted Average Per Well Baseline NWQEIs
0.00
0.00
0.00
0.00
1.80
2.61
0.00
0.00
0.00
0.00
129.84
185.66
Weighted avg. assumes 80% of wells haul
wastes and 20% grind and inject.
No. of Wells
18
57
12
7
15
8
18
57
12
7
15
8
TOTAL ANNUAL GOM BASELINE NWQEIs
0.00
0.00
0.00
0.00
27.05
20.87
47.92
0.00
0.00
0.00
0.00
1,947.58 1,485.24
3,432.82
A-56
-------
Worksheet No. 2
Non-Water Quality Environmental Impacts: Baseline Current Practice
Page 1 of 4
Region:
Technology:
Offshore California
Zero Discharge via Haul and Land Dispose
Model Well Types:
Deep Water Development
Shallow Water Development
Model Well Characteristics (Chapter VIII):
Deep Water Development
Shallow Water Development
Waste Drilling No. of No. of Dedicated Dedicated
Cuttings Vol. Length Cuttings Boat Trips Boat Idling
(bbls) (days) Boxes (Cap.=80 boxes) Time (hrs)
1,442 5.4 58 1 129.6
953 3.6 39 1 86.4
No. of Truck
Trips
(Cap.= 50 bbl)
29
20
Diesel Fuel Consumed (gal)
Fuel-Consuming
Deep Water
Shallow Water
Activity
Development
Development
Notes (All information below is detailed in Section IX.3.1.3.1)
Supply Boat Transit
(distance (mi)/boat speed(mi/hr) *
diesel usage rate (gal/hr))
2,260.87
2,260.87
Distance traveled by supply boats for all wells = 200 mi.
Supply boat average speed =11.5 mi/hr.
Supply boat diesel usage rate =130 gal/hr.
Supply Boat Maneuvering
(no. of boat trips * maneuvering time
per trip (hrs) * diesel usage rate (gal/hr))
25.30
25.30
Average maneuvering time per trip = 1 hour.
Supply boat diesel usage rate during maneuvering = 25.3 gal/hr.
Dedicated Supply Boat Loading
(Idling time per trip(hr) +
additional loading time per trip (hr)) *
no. of trips * diesel usage rate (gal/hr)
3,319.36
2,226.40
A dedicated supply boat is assumed to be moored and idling at the platform until it has
reached capacity or until all SBF generated cuttings from the drilling operation are loaded.
Idling supply boat diesel usage rate = 25.3 gal/hr.
Additional loading time to account for potential delays =1.6 hrs.
Supply Boat Auxiliary Generator
(in Port Demurrage)
(no. of boat trips * generator hrs per trip *
diesel usage rate (gal/hr))
144.00
144.00
Generator usage time in port = 24 hrs.
Generator diesel usage rate in port = 6 gal/hr.
A-57
-------
Worksheet No. 2
Non-Water Quality Environmental Impacts: Baseline Current Practice
Page 2 of 4
Region:
Technology:
Offshore California
Zero Discharge via Haul and Land Dispose
Model Well Types:
Deep Water Development
Shallow Water Development
Model Well Characteristics (Chapter VIII):
Deep Water Development
Shallow Water Development
Waste
Cuttings Vol.
(bbls)
1,442
953
Drilling
Length
(days)
5.4
3.6
No. of
Cuttings
Boxes
58
39
No. of Dedicated
Boat Trips
(Cap.=80 boxes)
1
1
Dedicated
Boat Idling
Time (hrs)
129.6
86.4
No. of Truck
Trips
(Cap.= 50 bbl)
29
20
Diesel Fuel Consumed (gal)
Fuel-Consuming
Deep Water
Shallow Water
Activity
Development
Development
Notes (All information below is detailed in Section IX.3.1.3.1)
Supply Boat Cranes
((no. of lifts at drill site + no of lifts in port)/
crane lifts per hour)) * diesel usage rate
193.26
129.95
Supply boat crane loading/unloading rate = 10 lifts per hour.
Supply boat crane diesel usage rate = 8.33 gal/hr.
Trucks
(no. of truck trips*roundtrip miles per trip)/
diesel usage rate (mi/gal)
1,242.86
857.14
Roundtrip distance from the port to the disposal facility = 300 miles.
Truck diesel usage rate = 7 mi/gal.
Wheel Tractor for Grading at Landfarm
(tractor time per well) * diesel usage rate
13.36
13.36
Tractor time per well for all well types = 8 hrs.
Tractor diesel usage rate = 1.67 gal/hr.
Track-Type Dozer/Loader for
Spreading Waste at Landfarm
(dozer time per well) * diesel usage rate
352.00
352.00
Dozer time per well for all well types =16 hrs.
Dozer diesel usage rate = 22 gal/hr.
TOTAL Diesel Per Well (Gal)
7,551.00
6,009.02
Power Requirements (hp-hr)
Energy-Consuming
Deep Water
Shallow Water
Activity
Development
Development
Notes (All information below is detailed in Section IX.3.1.3.1)
Supply Boat Auxiliary Generator
(in Port Demurrage)
no. of boat trips * generator hrs per trip *
generator power rating
1,440.00
1,440.00
In port use of auxiliary electrical generator for power = 24 hrs.
Generator power rating = 60 hp.
Supply Boat Cranes
((no. of lifts at drill site + no of lifts in port)/
crane lifts per hour)) * generator power rating
TOTAL Power Requirements Per Well
3,155.20
4,595.20
2,121.60
3,561.60
Generator power rating = 136 hp.
A-58
-------
Worksheet No. 2
Non-Water Quality Environmental Impacts: Baseline Current Practice
Air Emissions
Page 3 of 4
Region: Offshore California
Technology: Zero Discharge via Haul and Land Dispose
Model Well Types: Deep Water Development
Shallow Water Development
Deep Water Development Well Air Emissions
Category
Air Emissions (tons/per well drilled)
Total
NOx
THC
S02
CO
TSP
Supply Boats
Transit
0.443
0.190
0.032
0.089
0.037
0.791
Maneuvering
0.005
0.003
0.000
0.001
0.000
0.010
Loading
0.696
0.375
0.047
0.099
0.055
1.273
Demurrage
0.022
0.002
0.001
0.005
0.002
0.032
Supply Boat Cranes
0.049
0.004
0.003
0.011
0.003
0.070
Trucks
0.108
0.024
0.817
0.949
Wheel Tractor
0.005
0.001
0.000
0.014
0.001
0.021
Dozer/Loader
0.007
0.001
0.001
0.002
0.000
0.010
Total
1.33
0.60
0.09
1.04
0.10
3.15
Shallow Water Development Well Air Emissions
Category
Air Emissions (tons/per well drilled)
Total
NOx
THC
S02
CO
TSP
Supply Boats
Transit
0.443
0.190
0.032
0.089
0.037
0.791
Maneuvering
0.005
0.003
0.000
0.001
0.000
0.010
Loading
0.467
0.252
0.032
0.067
0.037
0.854
Demurrage
0.022
0.002
0.001
0.005
0.002
0.032
Supply Boat Cranes
0.033
0.003
0.002
0.007
0.002
0.047
Trucks
0.074
0.016
0.056
0.147
Wheel Tractor
0.005
0.001
0.000
0.014
0.001
0.021
Dozer/Loader
0.007
0.001
0.001
0.002
0.000
0.010
Total
1.06
0.47
0.07
0.24
0.08
1.91
A-59
-------
Worksheet No. 2
Non-Water Quality Environmental Impacts: Baseline Current Practice
Page 4 of 4
Region; Offshore California
Technology: Zero Discharge via Haul and Land Dispose
Model Well Types: Deep Water Development, Shallow Water Development
Per Well
Air Emissions (tons)
Fuel Usage (BOE)
NWQEI
DWD
SWD
TOTAL
DWD
SWD
TOTAL
Notes
Hauling and Onshore Disposal
(diesel fuel source)
3.1548
1.9111
179.79
143.07
From Worksheet No. 2, page 3
Total NWQEI Per Well
3.15
1.91
179.79
143.07
No. of Wells
11
1
11
1
TOTAL ANNUAL CA BASELINE NWQEIs
34.70
1.91
36.61
1,977.64
143.07
2,120.72
-------
Worksheet No. 4
Non-Water Quality Environmental Impacts: Discharge
Page 1 of 2
Region: Offshore Gulf of Mexico
Technology: Discharge via add-on drill cuttings "dryer" with average retention of 7%(wt) base fluid on cuttings.
Model Well Types: Deep Water Development, Deep Water Exploratory, Shallow Water Development, Shallow Water Exploratory
Model Well Characteristics (Chapter VIII):
Waste Drilling
Cuttings Vol. Length
(bbls) (days)
Deep Water Development 1,442 5.4
Deep Water Exploratory 3,206 12
Shallow W ater Development 953 3.6
Shallow Water Exploratory 1,997 7.5
Fuel-Consuming
Activity
Power Rec
uirements (hp-hr)
Notes (All information below is detailed in Section IX.3.1.2)
Deep Water
Shallow Water
Development
Exploratory
Development
Exploratory
Improved Solids Control Equipment
(hp * hrs to drill SBF well interval)
3,562.70
7,917.12
2,375.14
4,948.20
Total horsepower of solids control equipment = 27.49 hp.
Total Power Requirements Per Well
Total Natural Gas Usage Per Well (scf)
Total Diesel Usage Per Well (gal)
3,562.70
33,845.69
777.60
7,917.12
75,212.64
1,728.00
2,375.14
22,563.79
518.40
4,948.20
47,007.90
1,080.00
Fuel consumption rate = 6 gal/hr.
Fuel Type used on Platforms: Diesel Fuel
Air Emissions From Additional Solids Control Equipment (tons/per well drilled)
Category
THC
S02
CO
TSP
Total
Deep Water Development
0.0044
0.0037
0.0119
0.0039
0.0788
Deep Water Exploratory
0.0098
0.0081
0.0264
0.0087
0.1751
Shallow Water Development
0.0029
0.0024
0.0079
0.0026
0.0525
Shallow Water Exploratory
0.0061
0.0051
0.0165
0.0055
0.1094
Fuel Type used on Platforms: Natural Gas
Air Emissions From Additional Solids Control Equipment (tons/per well drilled)
Category
THC
S02
CO
TSP
Total
Deep Water Development
0.0007
0.0000
0.0033
0.0000
0.0091
Deep Water Exploratory
0.0016
0.0000
0.0072
0.0000
0.0202
Shallow Water Development
0.0005
0.0000
0.0022
0.0000
0.0060
Shallow Water Exploratory
0.0010
0.0000
0.0045
0.0000
0.0126
A-65
-------
Worksheet No. 4
Non-Water Quality Environmental Impacts: Discharge
Page 2 of 2
Region: Offshore Gulf of Mexico
Technology: Discharge via add-on drill cuttings "dryer" with average retention of 7%(wt) base fluid on cuttings.
Model Well Types: Deep Water Development, Deep Water Exploratory, Shallow Water Development, Shallow Water Exploratory
Per Well
Air Emissions (tons)
Fuel Usa
ze (BOE)
w\ nil
l>\\ 1)
I>\\ 1
s\\ 1)
s\\ 1
TOT U
l>\\ 1)
mw,
s\\ 1)
s\\ 1
TOT U
\nlr-.
<.<)\l \\ells ( uiTinll\ 1 -inn Mil- ;||||| l)iM'li:ii
iinii ( lining
Discharge Option
0.0788
0.1751
0.0525
0.1094
18.51
41.14
12.34
25.71
From Worksheet No. 4, page 1
(diesel fuel source)
Discharge Option
0.0091
0.0202
0.0060
0.0126
6.02
13.39
4.02
8.37
From Worksheet No. 4, page 1
(natural gas fuel source)
Weighted Average Per Well NWQEls
0.07
0.15
0.05
0.09
16.64
36.98
11.09
23.11
Weighted avg. assumes 85% of wells use diesel
and 15% use nat. gas for electricity generation.
No. of Wells
18
57
12
7
18
57
12
7
Subtotal Annual GOM XWQF.Is for SBF Wells
1.23
8.66
0.55
0.66
11.11)
299.53
2.107.84
133.13
161.79
2."112.28
(KIM Well- ( uiTinll\ 1 -inn()ltl- \>iimril l<>
Swiu li i<
SMI
Discharge Option
-
-
0.0525
0.1094
--
-
12.34
25.71
From Worksheet No. 4, page 1
(diesel fuel source)
Discharge Option
0.0060
0.0126
0.09
0.19
From Worksheet No. 4, page 1
(natural gas fuel source)
Weighted Average Per Well NWQEls
-
-
0.05
0.09
--
-
10.51
21.89
Weighted avg. assumes 85% of wells use diesel
and 15% use nat. gas for electricity generation.
No. of Wells
-
-
15
8
--
-
15
8
Subtotal Annual GOM NWQEls for OBF Wells
0.68
0.76
1.44
157.58
175.09
332.67
TOTAL ANNUAL GOM Discharge NWQEls
12.54
3,034.95
A-66
-------
Worksheet No. 5
Non-Water Quality Environmental Impacts: Discharge
Page 1 of 2
Region:
Technology:
Model Well Types:
Model Well Characteristics (Chapter VIII):
Deep Water Development
Shallow Water Development
Offshore California
Discharge via add-on drill cuttings "dryer" with average retention of 7%(wt) base fluid on cuttings.
Deep Water Development, Shallow Water Development
Waste
Cuttings Vol.
(bbls)
1,442
953
Drilling
Length
(days)
5.4
3.6
Power Requirements (hp-hr)
Fuel-Consuming
Deep Water
Shallow Water
Activity
Development
Development
Notes (All information below is detailed in Section IX.3.1.2)
Improved Solids Control Equipment
3,562.70
2,375.14
Total horsepower of solids control equipment = 27.49 hp.
(hp * hrs to drill SBF well interval)
Total Power Requirements Per Well
3,562.70
2,375.14
Total Natural Gas Usage Per Well (scf)
33,845.69
22,563.79
Shallow water wells drilled in Offshore California use natural gas as fuel for generating power.
Total Diesel Usage Per Well (gal)
777.60
Fuel consumption rate = 6 gal/hr.
Fuel Type used on Platforms:
Diesel Fuel
Air Emissions From Additional Solids Control Equipment (tons/per well drilled)
Category
NOx
THC
S02
CO
TSP
Total
Deep Water Development
0.0549
0.0044
0.0037
0.0119
0.0039
0.0788
Fuel Type used on Platforms:
Natural Gas
Air Emissions From Additional Solids Control Equipment (tons/per well drilled)
Category
NOx
THC
S02
CO
TSP
Total
Deep Water Development
0.0051
0.0007
0.0000
0.0033
0.0000
0.0091
Shallow Water Development
0.0034
0.0005
0.0000
0.0022
0.0000
0.0060
A-67
-------
Worksheet No. 5
Non-Water Quality Environmental Impacts: Discharge
Page 2 of 2
Region: Offshore California
Technology: Discharge via add-on drill cuttings "dryer" with average retention of 7%(wt) base fluid on cuttings.
Model Well Types: Deep Water Development, Shallow Water Development
Per Well
Air Emissions
(tons)
Fuel
Usage (BOE)
NWQEI
DWD
SWD
TOTAL
DWD
SWD
TOTAL
Notes
Discharge Option
(diesel fuel source for deep water wells only)
0.0788
18.51
From Worksheet No. 5, page 1
Discharge Option
(natural gas fuel source)
0.0091
0.0060
6.02
4.0164
From Worksheet No. 5, page 1
Weighted Average or Total Per Well NWQEIs
No. of Wells
0.07
11
0.0060
1
16.64
11
4.0164
1
Weighted avg. assumes 85% of wells use diesel
and 15% use nat. gas for electricity generation.
TOTAL ANNUAL CA DISCHARGE NWQEIs
0.75
0.01
0.76
183.05
4.02
187.07
A-68
-------
Worksheet No. 6
Non-Water Quality Environmental Impacts: Discharge
Page 1 of 2
Region:
Technology:
Cook Inlet, Alaska
Discharge via add-on drill cuttings "dryer" with average retention of 7%(wt) base fluid on cuttings.
Model Well Types:
Shallow Water Development
Model Well Characteristics (Chapter VIII):
Shallow Water Development
Waste
Cuttings Vol.
(bbls)
953
Drilling
Length
(days)
3.6
Fuel-Consuming
Activity
Power Requirements (hp-hr)
Notes (All information below is detailed in Section IX.3.1.2)
Shallow Water Development
Improved Solids Control Equipment
(hp * hrs to drill SBF well interval)
Total Power Requirements Per Well
Total Natural Gas Usage Per Well (scf)
2,375.14
2,375.14
22,563.79
Total horsepower of solids control equipment = 27.49 hp.
Wells drilled in Cook Inlet, Alaska use natural gas as fuel for generating power
Fuel Type used on Platforms: Natural Gas
Category
Air Emissions From Additional Solids Control Equipment (tons/per well drilled)
Total
NOx THC S02 CO TSP
Shallow Water Development
0.0034 0.0005 0.0000 0.0022 0.0000
0.0060
A-69
-------
Worksheet No. 6
Non-Water Quality Environmental Impacts: Discharge
Page 2 of 2
Region: Cook Inlet, Alaska
Technology: Discharge via add-on drill cuttings "dryer" with average retention of 7%(wt) base fluid on cuttings.
Model Well Types: Shallow Water Development
Per Well
Air Emissions (tons)
Fuel Usage (BOE)
NWQEI
SWD
TOTAL
SWD
TOTAL
Notes
Discharge Option
(natural gas fuel source)
0.0060
4.0164
From Worksheet No. 6, page 1
Total Per Well NWQEIs
0.0060
4.0164
No. of Wells
1
1
TOTAL ANNUAL AK DISCHARGE NWQEIs
0.01
0.01
4.02
4.02
A-70
-------
Worksheet No. 7
Non-Water Quality Environmental Impacts: Zero Discharge GOM
Page 1 of 4
Region: Offshore Gulf of Mexico
Technology: Zero Discharge via Haul and Land Dispose
Model Well Types: Deep Water Development, Deep Water Exploratory, Shallow Water Development, Shallow Water Exploratory
Model Well Characteristics (Chapter VIII):
Waste
Drilling
No. of
No. of Dedicated
Dedicated
No. of Regular
No. of Truck
Cuttings Vol.
Length
Cuttings
Boat Trips
Boat Idling
Boat Trips
Trips
(bbls)
(days)
Boxes
(Cap.=80 boxes)
Time (hrs)
(Cap.=12 boxes)
(Cap.=l 19 bbl)
Deep Water Development
1,442
5.4
58
1
129.6
0
13
Deep Water Exploratory
3,206
12
129
2
264.0
1
27
Shallow Water Development
953
3.6
39
1
86.4
0
8
Shallow Water Exploratory
1,997
7.5
80
1
180.0
0
17
Diesel Fuel Consumed (gal)
Fuel-Consuming
Deep W ater
Shallow Water
Activity
Development
Exploratory
Development
Exploratory
Notes (All information below is detailed in Section IX.3.1.3.1)
Supply Boat Transit
(distance (mi)/boat speed(mi/hr) *
diesel usage rate (gal/hr))
3,131.30
7,133.04
3,131.30
3,131.30
Distance travelled by supply boats for all wells except deep exploratory = 277 mi.;
for deep exploratory wells, supply boat distance = 631 mi.
Supply boat average speed = 11.5 mi/hr.
Supply boat diesel usage rate = 130 gal/hr.
Tug/Barge Transit
(distance/speed *diesel usage rate)
400.00
400.00
400.00
400.00
Barge capacity = 240 boxes. Only 1 barge trip is needed for all well types.
Barging distance = 100 mi.
Tug speed = 6 mi/hr.
Tug diesel usage rate = 24 gal/hr.
Supply Boat Maneuvering
(no. of boat trips * maneuvering time
per trip (hrs) * diesel usage rate (gal/hr))
25.30
75.90
25.30
25.30
Average maneuvering time per trip = 1 hour.
Supply boat diesel usage rate during maneuvering = 25.3 gal/hr.
Dedicated Supply Boat Loading
(Idling time per trip(hr) +
additional loading time per trip (hr))
no. of trips * diesel usage rate (gal/hr)
3,319.36
6,760.16
2,226.40
4,594.48
Dedicated supply boats are assumed to be moored and idling at the platform
until it has reached capacity or until all SBF generated cuttings from the
drilling operation are loaded.
Idling supply boat diesel usage rate = 25.3 gal/hr.
Regular Supply Boat Loading
((empty boxes + full boxes)/loading rate) +
additional loading time per trip (hr) *
no. of trips * diesel usage rate (gal/hr)
0
96.14
0
0
Loading rate =10 boxes/hr.
Additional loading time per trip =1.6 hrs.
Supply boat diesel usage rate during loading = 25.3 gal/hr.
Supply Boat Auxiliary Generator
(in Port Demurrage)
(no. of boat trips * generator hrs per trip *
diesel usage rate (gal/hr))
144.00
432.00
144.00
144.00
Generator usage time in port = 24 hrs.
Supply boat diesel usage rate in port = 6 gal/hr.
A-71
-------
Worksheet No. 7
Non-Water Quality Environmental Impacts: Zero Discharge GOM
Page 2 of 4
Region: Offshore Gulf of Mexico
Technology: Zero Discharge via Haul and Land Dispose
Model Well Types: Deep Water Development
Deep Water Exploratory
Shallow Water Development
Shallow Water Exploratory
Model Well Characteristics (Chapter VIII):
Waste
Drilling
No. of
No. of Dedicated Dedicated
No. of Regular
No. of Truck
Cuttings Vol.
Length
Cuttings
Boat Trips Boat Idling
Boat Trips
Trips
(bbls)
(days)
Boxes
(Cap.=80 boxes) Time (hrs)
(Cap.=12 boxes)
(Cap.=119 bbl)
Deep Water Development
1,442
5.4
58.0
1 129.6
0
13
Deep Water Exploratory
3,206
12.0
129.0
2 264.0
1
27
Shallow Water Development
953
3.6
39.0
1 86.4
0
8
Shallow Water Exploratory
1,997
7.5
80.0
1 180.0
0
17
Diesel Fuel Consumed (gal)
Fuel-Consuming
Deep Water
Shallow Water
Activity
Development
Exploratory
Development
Exploratory
Notes (All information below is detailed in Section IX.3.1.3.1)
Supply Boat Cranes
((no. of lifts at drill site + no of lifts in port)/
crane lifts per hour)) * diesel usage rate
193.26
429.83
129.95
266.56
Supply boat crane loading/unloading rate =10 lifts per hour.
Supply boat crane diesel usage rate =8.33 gal/hr.
Barge Cranes
((no. of lifts)/crane lifts per hour) *
diesel usage rate (gal/hr)
96.63
214.91
64.97
133.28
Barge crane loading/unloading rate =10 lifts per hour.
Barge crane diesel usage rate =8.33 gal/hr.
Trucks
(no. of truck trips*roundtrip miles per trip)/
diesel usage rate (mi/gal)
65.00
134.71
40.04
83.91
Roundtrip distance from the port to the disposal facility = 20 miles.
Truck diesel usage rate = 4 mi/gal.
Wheel Tractor for Grading at Landfarm
(tractor time per well) * diesel usage rate
13.36
13.36
13.36
13.36
Tractor time per well for all well types = 8 hrs.
Tractor diesel usage rate = 1.67 gal/hr.
Track-Type Dozer/Loader for
Spreading Waste at Landfarm
(dozer time per well) * diesel usage rate
352.00
352.00
352.00
352.00
Dozer time per well for all well types =16 hrs.
Dozer diesel usage rate = 22 gal/hr.
TOTAL Diesel Per Well (Gal)
7,740.21
16,042.05
6,527.33
9,144.19
A-72
-------
Worksheet No. 7
Non-Water Quality Environmental Impacts: Zero Discharge GOM
Page 3 of 4
Region: Offshore Gulf of Mexico
Technology: Zero Discharge via Haul and Land Dispose
Model Well Types: Deep Water Development
Deep Water Exploratory
Shallow Water Development
Shallow Water Exploratory
Model Well Characteristics (Chapter VIII):
Waste
Drilling
No. of
No. of
Dedicated
Dedicated
No. of Regular
No. of Truck
Cuttings Vol.
Length
Cuttings
Boat Trips
Boat Idling
Boat Trips
Trips
(bbls)
(days)
Boxes
(Cap.=80
boxes)
Time (hrs)
(Cap.=12 boxes)
(Cap.=119 bbl)
Deep Water Development
1,442
5.4
58
1
129.6
0
13
Deep Water Exploratory
3,206
12.0
129
2
264.0
1
27
Shallow Water Development
953
3.6
39
1
86.4
0
8
Shallow Water Exploratory
1,997
7.5
80
1
180.0
0
17
Power Requirements (hp-hr)
Energy-Consuming
Deep Water
Shallow Water
Activity
Development
Exploratory
Development
Exploratory
Notes (All information below is detailed in Section IX.3.1.3.1)
Supply Boat Auxiliary Generator
(in Port Demurrage)
no. of boat trips * generator hrs per trip *
generator power rating
1,440.00
4,320.00
1,440.00
1,440.00
In port use of auxiliary electrical generator power = 24 hrs.
Generator power rating = 60 hp.
Supply Boat Cranes
((no. of lifts at drill site + no of lifts in port)/
crane lifts per hour)) * generator power rating
3,155.20
7,017.60
2,121.60
4,352.00
Generator power rating = 136 hp.
Barge Cranes
((no. of lifts at drill site + no of lifts in port)/
crane lifts per hour)) * generator power rating
TOTAL Power Requirements Per Well
1,577.60
6,172.80
3,508.80
14,846.40
1,060.80
4,622.40
2,176.00
7,968.00
Generator power rating = 136 hp.
A-73
-------
Worksheet No. 7
Non-Water Quality Environmental Impacts: Zero Discharge GOM
Air Emissions
Page 4 of 4
Region:
Technology:
Offshore Gulf of Mexico
Zero Discharge via Haul and Land Dispose
Model Well Types:
Deep Water Development
Deep Water Exploratory
Shallow Water Development
Shallow Water Exploratory
Deep Water Development Well Air Emissions
Category
Air Emissions (tons/per well drilled)
Total
NOx
THC
S02
CO
TSP
Supply Boats
Transit
0.613
0.263
0.045
0.123
0.052
1.095
Maneuvering
0.005
0.003
0.000
0.001
0.000
0.010
Loading
0.696
0.375
0.047
0.099
0.055
1.273
Demurrage
0.022
0.002
0.001
0.005
0.002
0.032
Barge
Transit
0.078
0.034
0.006
0.016
0.007
0.140
Supply Boat Cranes
0.049
0.004
0.003
0.011
0.003
0.070
Barge Cranes
0.024
0.002
0.002
0.005
0.002
0.035
Trucks
0.003
0.001
-
0.002
-
0.006
Wheel Tractor
0.005
0.001
0.000
0.014
0.001
0.021
Dozer/Loader
0.007
0.001
0.001
0.002
0.000
0.010
Total Per Well
1.50
0.68
0.11
0.28
0.12
2.69
Deep Water Exploratory Well Air Emissions
Category
Air Emissions (tons/per well drilled)
Total
NOx
THC
S02
CO
TSP
Supply Boats
Transit
1.397
0.599
0.102
0.279
0.118
2.495
Maneuvering
0.016
0.009
0.001
0.002
0.001
0.029
Loading
1.418
0.764
0.096
0.202
0.112
2.592
Demurrage
0.067
0.005
0.004
0.014
0.005
0.096
Barge
Transit
0.078
0.034
0.006
0.016
0.007
0.140
Supply Boat Cranes
0.108
0.009
0.007
0.023
0.008
0.155
Barge Cranes
0.054
0.004
0.004
0.012
0.004
0.078
Trucks
0.007
0.001
-
0.005
-
0.013
Wheel Tractor
0.005
0.001
0.000
0.014
0.001
0.021
Dozer/Loader
0.007
0.001
0.001
0.002
0.000
0.010
Total Per Well
3.16
1.43
0.22
0.57
0.25
5.63
Shallow Water Development Well Air Emissions
Category
Air Emissions (tons/per well drilled)
Total
NOx
THC
S02
CO
TSP
Supply Boats
Transit
0.613
0.263
0.045
0.123
0.052
1.095
Maneuvering
0.005
0.003
0.000
0.001
0.000
0.010
Loading
0.467
0.252
0.032
0.067
0.037
0.854
Demurrage
0.022
0.002
0.001
0.005
0.002
0.032
Barge
Transit
0.078
0.034
0.006
0.016
0.007
0.140
Supply Boat Cranes
0.033
0.003
0.002
0.007
0.002
0.047
Barge Cranes
0.016
0.001
0.001
0.004
0.001
0.023
Trucks
0.002
0.000
-
0.002
-
0.004
Wheel Tractor
0.005
0.001
0.000
0.014
0.001
0.021
Dozer/Loader
0.007
0.001
0.001
0.002
0.000
0.010
Total Per Well
1.25
0.56
0.09
0.24
0.10
2.24
Shallow Water Exploratory Well Air Emissions
Category
Air Emissions (tons/per well drilled)
Total
NOx
THC
S02
CO
TSP
Supply Boats
Transit
0.613
0.263
0.045
0.123
0.052
1.095
Maneuvering
0.005
0.003
0.000
0.001
0.000
0.010
Loading
0.964
0.519
0.065
0.137
0.076
1.762
Demurrage
0.022
0.002
0.001
0.005
0.002
0.032
Barge
Transit
0.078
0.034
0.006
0.016
0.007
0.140
Supply Boat Cranes
0.067
0.005
0.004
0.015
0.005
0.096
Barge Cranes
0.034
0.003
0.002
0.007
0.002
0.048
Trucks
0.004
0.001
0.000
0.003
0.000
0.008
Wheel Tractor
0.005
0.001
0.000
0.014
0.001
0.021
Dozer/Loader
0.007
0.001
0.001
0.002
0.000
0.010
Total Per Well
1.80
0.83
0.13
0.32
0.14
3.22
A-74
-------
Worksheet No. 8
Non-Water Quality Environmental Impacts: Zero Discharge GOM
Page 1 of 2
Region:
T echnology:
Model Well Types:
Offshore Gulf of Mexico
Zero Discharge via On-site Grinding and Injection
Model Well Characteristics:
Waste
Drilling
Deep Water Development
(Chapter VIII)
Cuttings Vol.
Length
Deep Water Exploratory
(bbls)
(days)
Shallow Water Development
Deep Water Development
1,442
5.4
Shallow Water Exploratory
Deep Water Exploratory
3,206
12.0
Shallow Water Development
953
3.6
Shallow Water Exploratory
1,997
7.5
Fuel Type used on Platforms:
Diesel Fuel
Diesel Fuel Consumed (gal)
Fuel-Consuming
Deep Water
Shallow Water
Activity
Development
Exploratory
Development
Exploratory
Notes (All information below is detailed in Section IX.3.1.3.2)
Cuttings Transfer
hrs of operation * diesel usage rate
777.60
1,728.00
518.40
1,080.00
Hours of operation equals the drilling length in days multiplied by 24 hrs. per day
The transfer equipment utilizes one (1) 100 hp vacuum pump.
Diesel usage rate of the vacuum pump = 6 gal/hr.
Cuttings Grinding and Processing
hrs of operation * diesel usage rate
777.60
1,728.00
518.40
1,080.00
Hours of operation equals the drilling length in days multiplied by 24 hrs. per day
The grinding and processing equipment that utilize fuel include: one(l) 75 hp grinding
pump, two (2) 10 hp mixing pumps, two (2) 10 hp vacuum pumps, and one (1) 5 hp
shaker motor.
Diesel usage rate of the grinding and processing equipment = 6 gal/hr.
Cuttings Injection
hrs of operation * diesel usage rate
57.68
128.24
38.12
79.88
Hours of operation is based on one injection pump rated at 2.5 barrels per minute.
Diesel usage rate of the injection pump = 6 gal/hr.
TOTAL Diesel Consumed Per Well (gal)
1,612.88
3,584.24
1,074.92
2,239.88
Fuel Type used on Platforms: Natural Gas
Natural Gas Fuel Usage (scf)
Fuel-Consuming
Deep Water
Shallow Water
Activity
Development
Exploratory
Development
Exploratory
Notes (All information below is detailed in Section IX.3.1.3.2)
Cuttings Transfer
hrs of operation * hp * 9.5 scf/hp-hr
123,120
273,600
82,080
171,000
Hours of operation equals the drilling length in days multiplied by 24 hrs. per day
The transfer equipment utilizes one (1) 100 hp vacuum pump.
Cuttings Grinding and Processing
hrs of operation * hp * 9.5 scf/hp-hr
147,744
328,320
98,496
205,200
Hours of operation equals the drilling length in days multiplied by 24 hrs. per day
The grinding and processing equipment that utilize fuel include: one(l) 75 hp grinding
pump, two (2) 10 hp mixing pumps, two (2) 10 hp vacuum pumps, and one (1) 5 hp
shaker motor.
Cuttings Injection
hrs of operation * hp * 9.5 scf/hp-hr
54,796
121,828
36,214
75,886
Hours of operation is based on one (1) 600 hp injection pump rated at 2.5 barrels
per minute.
TOTAL Natural Gas Usage Per Well (scf)
325,660
723,748
216,790
452,086
A-75
-------
Worksheet No. 8
Non-Water Quality Environmental Impacts: Zero Discharge GOM
Air Emissions
Page 2 of 2
Region:
Technology:
Offshore Gulf of Mexico
Zero Discharge via On-site Grinding and Injection
Model Well Types:
Deep Water Development
Deep Water Exploratory
Shallow Water Development
Shallow Water Exploratory
Model Well Characteristics:
Deep Water Development
Deep Water Exploratory
Shallow Water Development
Shallow Water Exploratory
Drilling
Volume
Length
(bbls)
(days)
1,442
5.4
3,206
12.0
953
3.6
1,997
7.5
Total Equipment hp-hr
Fuel-Consuming
Deep Water
Shallow Water
Activity
Development
Exploratory
Development
Exploratory
Notes (All information below is detailed in Section IX.3.1.3.2)
Cuttings Transfer
hrs of operation * horsepower
22.50
50.00
15.00
31.25
Hours of operation equals the drilling length in days multiplied by 24 hrs. per day.
The transfer equipment utilizes one (1) 100 hp vacuum pump.
Cuttings Grinding and Processing
hrs of operation * horsepower
27.00
60.00
18.00
37.50
Hours of operation equals the drilling length in days multiplied by 24 hrs. per day.
The grinding and processing equipment that utilize fuel include: one(l) 75 hp grinding
pump, two (2) 10 hp mixing pumps, two (2) 10 hp vacuum pumps, and one (1) 5 hp
shaker motor.
Cuttings Injection
hrs of operation * horsepower
5,768.00
12,824.00
3,812.00
7,988.00
Hours of operation is based on one injection pump rated at 2.5 barrels per minute.
TOTAL Power Requirements Per Well
(hp In )
5,817.50
12,934.00
3,845.00
8,056.75
Fuel Type used on Platforms: Diesel Fuel
Air Emissions From Grinding
and Injection Operations (tons/per well drilled)
Category
NOx
THC
S02
CO
TSP
Total
Deep Water Development
0.0897
0.0072
0.0060
0.0194
0.0064
0.1287
Deep Water Exploratory
0.1994
0.0160
0.0133
0.0432
0.0142
0.2860
Shallow Water Development
0.0593
0.0047
0.0039
0.0128
0.0042
0.0850
Shallow Water Exploratory
0.1242
0.0099
0.0083
0.0269
0.0089
0.1782
Fuel Type used on Platforms: Natural Gas
Air Emissions From Grinding
and Injection Operations (tons/per well drilled)
Category
NOx
THC
S02
CO
TSP
Total
Deep Water Development
0.0083
0.0012
0.0000
0.0053
0.0000
0.0148
Deep Water Exploratory
0.0185
0.0026
0.0000
0.0118
0.0000
0.0329
Shallow Water Development
0.0055
0.0008
0.0000
0.0035
0.0000
0.0098
Shallow Water Exploratory
0.0115
0.0016
0.0000
0.0074
0.0000
0.0205
A-76
-------
Worksheet No. 9
Non-Water Quality Environmental Impacts: Zero Discharge GOM
Region: Offshore Gulf of Mexico
Technology: Zero Discharge
Model Well Types: Deep Water Development, Deep Water Exploratory, Shallow Water Development, Shallow Water Exploratory
Per Well
Air Emissions (tons)
Fuel Usag
e (BOE)
NWQEI
DWD
DWE
SWD
SWE
TOTAL
DWD
DWE
SWD
SWE
TOTAL
Notes
GOM W i lls C ,'urmitly I sing SUE Assuming to Switch to OI5I I ndcr Zero Discharge
Hauling and Onshore Disposal
2.2358
3.2222
155.41
217.72
From Worksheet No.7
(diesel fuel source)
Grinding and Injection
-
-
0.0850
0.1782
-
-
25.59
53.33
From Worksheet No.8
(diesel fuel source)
Grinding and Injection
0.0098
0.0205
38.59
80.47
From Worksheet No.8
(natural gas fuel source)
Weighted Average Grinding and Injection
0.0737
0.1545
27.54
57.40
Weighted avg. assumes 85% of wells use diesel
and 15% use nat. gas for electricity generation.
Weighted Average NWQEI Per Well
1.80
2.61
129.84
185.66
Weighted avg. assumes 80% of wells haul
wastes and 20% grind and inject.
No. of Wells
12
7
12
7
Subtotal Annual GOM MYQF.Is for OliF Wells
21.64
18.26
1.558.06
1.299.59
2.S5".(i5
(!()M Well" ( iirmill\ 1 MSI- \->MiiiH'il In Urlain MSI- 1 ntlrr /.en> Disilini
-if
I Ianling and ()nshore Disposal
2.6916
5.6286
-
-
184.29
381.95
-
-
l-rom Worksheet No.7
(diesel fuel source)
Grinding and Injection
0.1287
0.2860
-
-
38.40
85.34
-
-
From Worksheet No.8
(diesel fuel source)
Grinding and Injection
0.0148
0.0329
57.97
128.83
From Worksheet No.8
(natural gas fuel source)
Weighted Average Grinding and Injection
0.1116
0.2481
41.34
91.86
Weighted avg. assumes 85% of wells use diesel
and 15% use nat. gas for electricity generation.
Weighted Average NWQEI Per Well
2.18
4.55
155.70
323.94
Weighted avg. assumes 80% of wells haul
wastes and 20% grind and inject.
No. of Wells
18
57
18
57
Subtotal Annual GOM NWQEls for SBF Wells
39.16
259.49
298.65
2,802.60
18,464.31
21,266.91
TOTAL Annual GOM Zero Discharge NWQEls
338.55
24,124.56
A-77
-------
A-78
-------
APPENDIX IX-2
NSPS NON-WATER QUALITY ENVIRONMENTAL IMPACT
CALCULATIONS FOR NEW SOURCES
A-79
-------
A-80
-------
Summary NSPS NWQEI of SBF Cuttings Management (a)
Baseline NWQEI: Total Annual
Baseline Technology
Gulf of Mexico
Total
Notes
Air Emissions
(tons)
Fuel Usage
(BOE), (b)
Air Emissions
(tons)
Fuel Usage
(BOE), (b)
Discharge with 11% retention of base
fluid on cuttings
0
0
0.00
0.00
Compliance NWQEI: Total Annual
Option
Gulf of Mexico
Total
Notes
Air Emissions
(tons)
Fuel Usage
(BOE), (b)
Air Emissions
(tons)
Fuel Usage
(BOE), (b)
Discharge Option
1.28
310.63
1.28
310.63
From Worksheet 2
Zero Discharge Option
40.96
2,932.44
40.96
2,932.44
From Worksheet 3
Incremental Compliance NWQEI Reductions: Total Annual
Gulf of Mexico
Total
Air Emissions
Fuel Usage
Air Emissions
Fuel Usage
Option
(tons)
(BOE), (b)
(tons)
(BOE), (b)
Notes
Discharge Option
(1.28)
(310.63)
(1.28)
(310.63)
Difference between total baseline and
compliance discharge option NWQEIs
Zero Discharge Option
(40.96)
(2,932.44)
(40.96)
(2,932.44)
Difference between discharge baseline
and zero discharge option NWQEIs
(a) The NSPS NWQEI analysis was conducted for 18 DWD wells and 1 SWD well currently using SBF in the Gulf of Mexico.
(b) BOE (barrels of oil equivalent) is the sum of the volumes of diesel (1 BOE = 42 gal diesel) and natural gas (1,000 scf = 0.178 BOE) estimated for each
compliance option.
A-81
-------
Worksheet No. 1
Non-Water Quality Environmental Impacts: Baseline Current Practice
Region: Offshore Gulf of Mexico
Technology: Discharge of SBF cuttings via add-on cuttings "dryer" w/average achievable retention of 11% (wt) base fluid
on cuttings
Model Well Types: Deep Water Development, Deep Water Exploratory, Shallow Water Development, Shallow Water
Exploratory
Air Emissions (tons)
Fuel Usage (BOE)
NWQEI
DWD
DWE
SWD
SWE
TOTAL
DWD
DWE
SWD
SWE
TOTAL
Notes
Discharge with 11% retention of base fluid
on cuttings (85% diesel, 15% nat. gas usage)
0.00
-
0.00
-
0.00
0.00
-
0.00
-
0.00
Average Per Well Baseline NWQEIs
0.00
-
0.00
-
0.00
-
0.00
-
No. of New Source Wells
18
-
1
-
18
-
1
-
TOTAL ANNUAL GOM BASELINE
NWQEIs
(New Sources)
0.00
0.00
0.00
0.00
0.00
0.00
A-82
-------
Worksheet No. 2
Non-Water Quality Environmental Impacts: Discharge
Region: Offshore Gulf of Mexico
Technology: Discharge via add-on drill cuttings "dryer" with average retention of 7%(wt) base fluid on cuttings.
Model Well Types: Deep Water Development, Deep Water Exploratory, Shallow Water Development, Shallow Water Exploratory
Per Well
Air Emissions (tons)
Fuel Usage (BOE)
NWQEI
DWD
DWE
SWD
SWE
TOTAL
DWD
DWE
SWD
SWE
TOTAL
Notes
Discharge Option
(diesel fuel source)
0.0788
0.0525
18.51
12.34
Worksheet No. 4, Appendix IX-1
Discharge Option
(natural gas fuel source)
0.0091
--
0.0060
--
6.02
--
4.02
--
Worksheet No. 4, Appendix IX-1
Weighted Average Per Well NWQEIs
0.07
0.05
16.64
11.09
Weighted avg. assumes 85% of
wells use diesel and 15% use
nat. gas for electricity generation.
No. of New Wells
18
1
18
1
Subtotal Annual GOM NWQEIs for SBF Wells
1.23
0.05
1.28
299.53
11.09
310.63
TOTAL ANNUAL GOM Discharge NWQEIs
1.28
310.63
A-83
-------
Worksheet No. 3
Non-Water Quality Environmental Impacts: Zero Discharge GOM
Region: Offshore Gulf of Mexico
Technology: Zero Discharge
Model Well Types: Deep Water Development, Deep Water Exploratory, Shallow Water Development, Shallow Water Exploratory
Per Well
Air Emissions (tons)
Fuel Usage (BOE)
NWQEI
DWD
DWE
SWD
SWE
TOTAL
DWD
DWE
SWD
SWE
TOTAL
Notes
Hauling and Onshore Disposal
2.6916
2.2358
184.29
155.41
Worksheet No. 7, Appendix IX-1
(diesel fuel source)
Grinding and Injection
0.1287
-
0.0850
38.40
-
25.59
Worksheet No. 8, Appendix IX-1
(diesel fuel source)
Grinding and Injection
0.0148
0.0098
57.97
38.59
Worksheet No. 8, Appendix IX-1
(natural gas fuel source)
Weighted Average Grinding and Injection
0.1116
0.0737
41.34
27.54
Weighted avg. assumes 85% of
wells use diesel and 15% use
nat. gas for electricity generation.
Weighted Average NWQEI Per Well
2.18
1.80
155.70
129.84
Weighted avg. assumes 80%) of
wells haul wastes and 20%
grind and inject.
No. of New Source Wells
18
1
18
1
Subtotal Annual GOM NWQEIs for New Wells
39.16
1.80
40.96
2,802.60
129.84
2,932.44
TOTAL Annual GOM Zero Discharge NWQEIs
(New Sources)
40.96
2,932.44
A-84
-------
Summary NSPS NWQEI of SBF Cuttings Management (a)
Baseline NWQEI: Total Annual
Baseline Technology
Gulf of Mexico
Total
Notes
Air Emissions
(tons)
Fuel Usage
(BOE), (b)
Air Emissions
(tons)
Fuel Usage
(BOE), (b)
Discharge with 11% retention of base fluid
on cuttings
0
0
0.00
0.00
Compliance NWQEI: Total Annual
Option
Gulf of Mexico
Total
Notes
Air Emissions j Fuel Usage
(tons) (BOE), (b)
Air Emissions
(tons)
Fuel Usage
(BOE), (b)
Discharge Option
1.28 310.63
1.28
310.63
From Worksheet 2
Zero Discharge Option
40.96| 2,932.44
40.96
2,932.44
From Worksheet 3
Incremental Compliance NWQEI Reductions: Total Annual
Option
Gulf of Mexico
Total
Notes
Air Emissions
(tons)
Fuel Usage
(BOE), (b)
Air Emissions
(tons)
Fuel Usage
(BOE), (b)
Discharge Option
(1.28)
(310.63)
(1.28)
(310.63)
Difference between total baseline and
compliance discharge option NWQEls
Zero Discharge Option
(40.96)
(2,932.44)
(40.96)
(2,932.44)
Difference between discharge baseline
and zero discharge option NWQEls
(a) The NSPS NWQEI analysis was conducted for 18 DWD wells and 1 SWD well currently using SBF in the Gulf of Mexico.
(b) BOE (barrels of oil equivalent) is the sum of the volumes of diesel (1 BOE = 42 gal diesel) and natural gas (1,000 scf = 0.178 BOE) estimated for each
compliance option.
-------
Worksheet No, 1
Non-Water Quality Environmental Impacts: Baseline Current Practice
Region: Offshore Gulf of Mexico
Technology: Discharge of SBF cuttings via add-on cuttings "dryer" w/average achievable retention of 11% (wt) base fluid
on cuttings
Model Well Types: Deep Water Development, Deep Water Exploratory, Shallow Water Development, Shallow Water
Exploratory
Air Emissions (tons)
Fuel Usage (BOE)
NWQEI
DWD
DWE
SWD
SWE
TOTAL
DWD
DWE
SWD
SWE
TOTAL
Notes
Discharge with 11% retention of base fluid
on cuttings (85% diesei, 15% nat gas usage)
0.00
0.00
0.00
0.00
--
0.00
-
0.00
Average Per Well Baseline NWQEIs
0.00
-
0.00
-
0.00
-
0.00
-
No. of New Source Wells
18
--
1
-
18
--
1
"
TOTAL ANNUAL GOM BASELINE NWQEIs
(New Sources)
0.00
0.00
0.00
0.00
0.00
0.00
-------
Worksheet No, 2
Non-Water Quality Environmental Impacts; Discharge
Region: Offshore Gulf of Mexico
Technology: Discharge via add-on drill cuttings "dryer" with average retention of 7%(wt) base fluid on cuttings.
Model Well Types: Deep Water Development, Deep Water Exploratory, Shallow Water Development, Shallow Water Exploratory
oo
w
Per Well
Air Emissions (tons)
Fuel Usage (BOE)
NWQEI
DWD
DWE
SWD
SW1
TOTAL
DWD | DWE
SWD
SWE
TOTAL
Notes
Discharge Option
(diesel fuel source)
0.0788
0.0525
18.51 --
12,34
"
Worksheet No. 4, Appendix IX-1
Discharge Option
(natural gas fuel source)
0.0091
--
0.0060
--
6.02 -
4.02
-
Worksheet No. 4, Appendix IX-1
Weighted Average Per Well NWQEIs
0.07
0.05
16.64
11.09
Weighted avg. assumes 85% of
wells use diesel and 15% use
nat. gas for electricity generation.
No. of New Wells
18
1
18
1
Subtotal Annual GOM NWQEIs for SBF Wells
1.23
0.05
1.28
299.53
11.09
310.63
TOTAL ANNUAL GOM Discharge NWQEIs
1.28
310.63
-------
Worksheet No. 3
Non-Water Quality Environmental Impacts: Zero Discharge GOM
Region; Offshore Gulf of Mexico
Technology: Zero Discharge
Model Well Types: Deep Water Development, Deep Water Exploratory, Shallow Water Development, Shallow Water Exploratory
Per Well
Air Emissions (tons)
Fuel Usage (BOl)
NWQEI
DWD
DWE SWD
SWE
TOTAL
DWD
DWE
SWD SWE
TOTAL
Notes
Hauling and Onshore Disposal
2.6916
2.2358
184.29
155.41
Worksheet No. 7, Appendix IX-1
(diesel fuel source)
Grinding and Injection
0.1287
0.0850
38.40
-
25.59
Worksheet No. 8, Appendix IX-1
(diesel fuel source)
Grinding and Injection
0.0148
0.0098
57.97
..
38.59
Worksheet No. 8, Appendix IX-1
(natural gas fuel source)
Weighted Average Grinding and Injection
0.1116
0.0737
41.34
27.54
Weighted avg. assumes 85% of
wells use diesel and 15% use
nat. gas for electricity generation.
Weighted Average NWQEI Per Well
2.18
1.80
155.70
129.84
Weighted avg. assumes 80% of
wells haul wastes and 20%
grind and inject.
No. of New Source Wells
18
1
18
1
Subtotal Annual GOM NWQEIs for New Wells
39.16
1.80
40,96
2,802.60
129.84
2,932.44
TOTAL Annual GOM Zero Discharge NWQEIs
(New Sources)
40.96
2,932.44
------- |